best practice catalogue for hydropower

Best Practice Catalog

Revision 1.0, 1/20/2012

HAP – Best Practice Catalog

Rev. 1.0, 1/20/2012 2

Prepared by

MESA ASSOCIATES, INC.

Chattanooga, TN 37402

Hydro Performance Processes Inc.

Doylestown, PA 18901-2963

and

OAK RIDGE NATIONAL LABORATORY

Oak Ridge, TN 37831-6283

managed by

UT-BATTELLE, LLC

for the

U. S. DEPARTMENT OF ENERGY

under contract DE-AC05-00OR22725


Rev. 1.0, 1/20/2012 3

Table of Contents

Trash Racks and Intakes ................................................................................................................................ 4

Penstocks and Tunnels ................................................................................................................................ 19

Flumes and Open Channels ........................................................................................................................ 39

Leakage and Releases ................................................................................................................................. 68

Francis Turbine ............................................................................................................................................ 78

Kaplan/Propeller Turbine .......................................................................................................................... 101

Pelton Turbine........................................................................................................................................... 126

Lubrication System .................................................................................................................................... 146

Governor ................................................................................................................................................... 165

Shut-Off Valves ......................................................................................................................................... 185

Raw Water System .................................................................................................................................... 197

Generator .................................................................................................................................................. 215

Main Power Transformer .......................................................................................................................... 240

Excitation System ...................................................................................................................................... 257

Instruments and Controls for Automation ............................................................................................... 272

Machine Condition Monitoring ................................................................................................................. 300

Francis Turbine Aeration ........................................................................................................................... 315


Trash Racks and Intakes

Revision 1.0, 12/01/2011

HAP – Best Practice Catalog – Trash Racks and Intakes

Rev. 1.0, 12/21/2011 5

Contents

1.0 Scope and Purpose ................................................................................................................... 6

1.1 Hydropower Taxonomy Position ..................................................................................... 6

1.1.1 Components............................................................................................................................. 6

1.2 Summary of Best Practices .............................................................................................. 8

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ............................... 8

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices .............................. 8

1.3 Best Practice Cross-References ........................................................................................ 8

2.0 Technology Design Summary .............................................................................................. 9

2.1 Material and Design Technology Evolution .................................................................... 9

2.2 State of the Art Technology .................................................................................................. 9

3.0 Operation and Maintenance Practices ................................................................................ 10

3.1 Condition Assessment .................................................................................................... 10

4.0 Metrics, Monitoring and Analysis ..................................................................................... 15

4.1 Measures of Performance, Condition, and Reliability ....................................................... 15

4.3 Integrated Improvements................................................................................................ 16

5.0 Information Sources: .......................................................................................................... 17


Rev. 1.0, 12/21/2011 6

1.0 Scope and Purpose

This best practice for trash racks and intakes addresses the technology, condition assessment,

operations, and maintenance best practices with the objective to maximize performance and

reliability.

The primary purpose of the trash rack is to protect the equipment by keeping floating debris,

leaves, and trash from entering the turbines. The primary purpose of the intake is to divert water

at the river/reservoir source and deliver the required flow into the penstocks which in turn feed

the hydropower plant.

1.1 Hydropower Taxonomy Position

Hydropower Facility → Water Conveyances → Trash Racks and Intakes

1.1.1 Components

The components of the trash rack and intake systems are those features that directly or

indirectly contribute to the efficiency of water conveyance operations. The trash rack

system is made up of the trash rack itself along with its cleaning and monitoring

components. The intake system is comprised primarily of the intake structure, intake

gates, and hoisting machinery.

Trash Rack: The primary function of trash racks is to protect equipment, such as wicket

gates and turbines, from debris that is too large to pass through without causing harm.

The trash rack is probably the single most important debris control device [1]. Typically,

a trash rack consists of stationary rows of parallel carbon steel bars located at the dam

intake.

Trash Rake: The function of the trash rake is to remove any debris that accumulates on

the trash rack. By cleaning clogged racks, trash rakes reduce head differential. Rakes vary

in size to accommodate a variety of debris sizes. Rakes also vary in level of automation

with some plants using manual trash rakes and others using mechanical systems.

Trash Conveyor: The function of the trash conveyor is to remove trash cleaned from trash

racks. Trash conveyors reduce cost by eliminating the need for manual trash removal.

Monitoring System: The function of a monitoring system is to measure head differential

across a trash rack. The measurements can then be used to schedule trash cleaning or

justify improvements.

Intake: The function of an intake is to divert water from a source such as a river,

reservoir, or forebay under controlled conditions into the penstocks leading to the power

plant. Intakes are designed to deliver the required flow over the desired range of

headwater elevations with maximum hydraulic efficiency.

Intake Structures: Intake structures are commonly built into the forebay side of the dam

immediately adjacent to the turbine. Another common intake design is a tower structure

connected to a penstock. Tower intakes are often separate structures in the reservoir,

typically constructed of reinforced concrete. Intake structures commonly house (1) trash


Rev. 1.0, 12/21/2011 7

racks that prevent large debris and ice from entering the water passages and (2) gates or

valves for controlling the flow of water and for dewatering of the intake for maintenance

purposes.

Intake Gates: An intake gate is arranged to shut off the water delivery when the conduit

system has to be emptied. Types of gates include hydraulically operated slide gates,

roller and wheel-mounted gates, and radial gates.

Stoplogs/Bulkhead Gates: Stop logs and bulkhead gates are used to block water so that

construction, maintenance, or repair work can be accomplished in a dry environment.

Stop logs are stored in a secure storage yard, positioned by a crane and dropped into slots

on the pier of a dam to form a wall against the water.

Air Vents: Air vents are typically incorporated in the intake structure and configured to

prevent collapse of the penstock due to excessive vacuum when closing the intake gates.

Hoisting Machinery: Hoists are mechanical (electrically or manually driven), hydraulic

(oil or water), or pneumatically operated machines used to raise and lower in place heavy

water control features such as gates and stop logs.

Figure 1: Illustrations of submerged intakes built into the face of the dam


Rev. 1.0, 12/21/2011 8

Figure 2: Tower intake structures (Left: Blue Ridge Dam, Fannin County, Georgia; Right: Hoover Dam,

Clark County, Nevada/Mohave County, Arizona)

1.2 Summary of Best Practices

1.2.1Performance/Efficiency & Capability - Oriented Best Practices

Routinely monitor and record unit performance at CPL.

Periodically compare the CPL to the PPL to trigger feasibility studies of major

upgrades.

1.2.2Reliability/Operations & Maintenance - Oriented Best Practices

Routinely inspect trash racks for degradation.

Trend trash rack degradation and adjust life expectancy accordingly.

Routinely clean trash racks, regulated by visual inspection, timed intervals, or

head differential monitoring.

Routinely inspect and maintain trash rack cleaning systems (e.g. trash rakes,

conveyors).

Maintain documentation of IPL and update when modification to equipment is

made (e.g. trash rack replacement/repair, trash rake addition/upgrade).

Include industry knowledge for modern trash rack system components and

maintenance practices to plant engineering standards.

1.3 Best Practice Cross-References

Civil – Penstocks, Tunnels, and Surge Tanks

Civil – Flumes/Open Channels

Civil – Draft Tube Gates

Civil – Leakage and Releases


Rev. 1.0, 12/21/2011 9

2.0 Technology Design Summary

2.1 Material and Design Technology Evolution

Traditionally, trash racks were cleaned by hand with equipment developed by the personnel

who used it (i.e., management and staff). Thus, these hand rakes became easier and easier to

handle and some even had wheels. Even today, some hydropower plants clean their trash

racks by hand. This requires intense manpower at times, particularly in the autumn when

rivers are full of fallen leaves. The size and position of trash racks were influenced by the

necessities of manual trash rack cleaning. Issues with manual cleaning of trash racks,

including limitations on the flow rate and economic inefficiencies, led to mechanization of

trash rack cleaners several decades ago. Initial mechanization involved trash racks that were

crossed upwards by a chain driven scraper with the collected trash dumped into a cross belt.

Chain-driven trash rack cleaning machines are still in use today at small hydropower plants

and quickly evolved into the classical wire rope trash rack cleaning machines that are in use

today at medium and large plants.

2.2 State of the Art Technology

Currently used trash rack apparatus can be categorized by hydropower plant size. For

medium-sized hydropower plants with cleaning lengths up to 65 feet, two types of trash rack

cleaning machines are typically used: the classic wire rope trash rack cleaner, and more

recently the hydraulic jib trash rack cleaner. For large-scaled hydropower plants, the wire

rope trash rack cleaner is used.

While the wire rope type trash rack cleaner has been in use for about 100 years, many

advances have been made by the way it is transported. Many solutions to the debris storage

problem have been created with examples being integrated containers used as buffer storage

containers towed by the cleaner and trucks that follow the trash rack cleaning machine under

their own power or by being positioned on a platform connected to the cleaner. Wire rope

type trash rack cleaners can be used for nearly unlimited cleaning lengths such as 200 feet.

The inclination of the trash rack should be at least 10 degrees to the vertical.

The hydraulic jib trash rack cleaners, which have been manufactured for only a few years

now, have a base frame with a travelling device along with a pivoted machine house with

booms and a grab rake [10]. The revolving superstructure of the machine enables dropping

of the trash beside or behind the railway of the trash rack cleaner. The grab rake is designed

to pick up oversized trees as well as to push floating debris to the weir. It has a scraper

sliding along the trash rack bars. The grab rake can be rotated to conform to the position of a

tree or other debris. Therefore, floating debris can be pushed to the weir to be drifted and

large debris, such as trees, can be picked up by the grab rake and disposed of. The cleaning

length is limited to about 50 to 60 feet, with greater cleaning lengths requiring the use of

telescopic beams. This device also makes possible the use of cleaning vertical trash racks.

Intakes are designed to deliver the required flow over the desired range of headwater

elevations with maximum hydraulic efficiency. Modern design basis requirements include

geologic, structural, hydraulic and environmental attributes. The intake design should shape

the water passages such that transformation of static head to conduit velocity is gradual,


Rev. 1.0, 12/21/2011 10

eddy and head losses are minimized, and the formation of vortices at the intake are limited.

Advancement in computer modeling technology has yielded a more accurate design of intake

structures for hydrodynamic loads, and particularly for updated seismic criteria as specified

by modern building codes.

Hydraulic head losses can be mitigated during the intake design by limiting the velocity of

the water through the trash rack and minimizing the acceleration of the water to achieve a

smooth rate of acceleration. Trash racks should not be exposed and the intake gate lintel

should be submerged below the minimum forebay level to lessen potential problems caused

by air entrainment.

3.0 Operation and Maintenance Practices

3.1 Condition Assessment

If trash racks are located at or near the water surface, visual inspection from the surface may

be possible. If trash racks are located far enough below the water surface that they cannot be

seen from the surface, divers, underwater cameras, and/or ROVs (Remotely Operated

Vehicles) may be used to perform inspections.

―ROV‘s may provide a more cost effective method for performing inspections – inspections

that previously would have required risky diving operations or costly facilities dewatering

[8].‖ The use of a new ROV system saved the U.S. Bureau of Reclamation more money in

fixing one ―serious problem‖ than the cost of the ROV [9]. ―ROVs can often work in

hazardous areas without requiring the dam to stop and tag out intakes and are not subject to

diving limits of depth or duration [9].‖ Using sonar, ROV‘s can also work in low and zero-

visibility environments. Both still and sonar images taken with a ROV can be seen in Figures

3 and 4 on the following page.

Plants should use manual or automated measurement tools whenever possible to monitor and

record head differentials across trash racks to determine energy losses. Data from these

measurements can be used to schedule trash rack cleanings and can be incorporated into

systems for unit, plant, and system optimization [7]. When head differential data is used to

quantify lost production, the calculated economic losses can be used to justify funding for

improvements in trash rack cleaning methods and/or trash rack design [7].

The unique orientation of the intake structure in relation to the incoming water may have a

significant impact on the overall effectiveness of the intake. Civil aspects of intakes include

not only the structure, but also the gates that control the flow. Intake gate life expectancy

should be at least 50 years, however corrosive water chemistry, poor coating performance

and lack of maintenance can greatly shorten service life [11].

Hydro plant structures have design features to accommodate gates. These features include

slots in piers and walls, and steel embedments that provide bearing/sealing surfaces for the

gates. The installation of the gates also typically requires hoist lifting machinery. As the

hydro plant ages, the intake gates are subject to wear, corrosion and physical damage. Seals

other than metallic are subject to environmental deterioration. Metallic seals are subject to


Rev. 1.0, 12/21/2011 11

wear. Coating systems can wear or fail exposing steel to corrosion. The hoist lifting systems

are subject to mechanical wear.

Concrete structures should be inspected for cracking and spalling, and observed cracks

should be monitored to determine if the cracks are progressing or dormant. It is essential to

note if the concrete defects are structural or non-structural. Although non-structural distress

such as local spalling due to insufficient concrete cover may be unsightly, it is less likely to

need to be addressed through remediation than structural cracking. Guides available to assist

with concrete condition assessment include U.S. Army Corps of Engineers Manual EM-

1110-2-2002, the U.S. Bureau of Reclamation Guide to Concrete Repair, and the American

Concrete Institute Standards 201.1 and 364.1R.

Figure 3: ROV Still Image of Trash Rack*

Figure 4: ROV Sonar Image of Trash

Rack*

*Photos were taken using a VideoRay Pro 4 ROV and are courtesy of VideoRay LLC.

3.2 Operation

Efficient and timely cleaning of trash racks can have a significant impact on the plant‘s

efficiency and generation. Trash racks capture debris on their upstream surface which

creates an energy (head) loss as water passes through them [6]. This energy loss can be

excessive when the rack is clogged, reducing the net head for generation and potentially

causing a significant reduction in plant efficiency. Although hydraulic losses due to debris

accumulation can be costly, they are one of the most common avoidable losses occurring in

hydropower plants [2]. Experience has shown that custom-engineered cleaning of trash racks

can provide annual power production increases of up to 25% [7]. While there is a cost for

cleaning equipment and cleaning operations, the benefits can be significant. Improved trash

rack design can also improve efficiency and generation for clean, unclogged racks.

―If there is a need to intercept trash with a trash rack, then there is a need to remove the

intercepted trash so that the flow of the water will not be hindered [6].‖ Some hydro plants


Rev. 1.0, 12/21/2011 12

have such a relatively small and/or infrequent debris load that cleaning can be carried out

manually. Other plants have large debris loads (Figure 5), which require mechanical

cleaning. Selection of trash rack cleaning equipment is site-specific.

Figure 5: Debris removed from trash racks can range in size from

aquatic milfoil to tree trunks, shown here [2]

Plants located in colder regions may have the additional problem of frazil ice accumulation

on trash racks. This ice affects trash rack efficiency in the same manner as debris, clogging

the trash rack and reducing the net generation head. In some cases frazil ice may be removed

by trash rakes, but in others, additional systems are needed to prevent the accumulation of

frazil ice [3]. See the discussion on frazil ice prevention in the following section for more

information.

The frequency of trash rack cleaning is site-specific and will vary from season to season at

each plant. Cleaning systems should be operated as frequently as needed to maintain plant

efficiency and capacity. Using head differential data as discussed in the above section, an

automated cleaning system can be installed. See the discussion on automated trash rakes in

the following section for more information.

3.3 Maintenance

As described in the system components, trash racks traditionally have been made of parallel

bars, and such installations have often served well for many decades. Carbon steel trash racks

typically need a protective coating, such as epoxy paint, to increase their life expectancy,

particularly if portions of the trash rack are periodically exposed to the atmosphere. In some

cases, it is cheaper to replace structurally weakened racks than it is to repaint them

periodically [6].

When trash racks are replaced, consideration should be given to improve trash rack design,

including modifications to bar shape and increased corrosion protection. Hydrodynamically

shaped bars have lower head losses, are less affected by flow-induced vibration, and are more


Rev. 1.0, 12/21/2011 13

easily cleaned [4]. To protect against corrosion, stainless steel, high density polyethylene

(HDPE), and fiber reinforced polymer (FRP) trash racks are available. The life expectancy of

steel trash racks is typically 15 to 35 years and 25 to 50 years for plastic or fiberglass trash

racks [3]. Some installations also use cathodic protection systems to combat corrosion. These

systems create a galvanic cell between the trash rack and an attached metal. The attached

metal suffers corrosion, thereby protecting the trash rack [6]. Additional guidance in the

replacement and detailed design of trash racks can be found in The Guide to Hydropower

Mechanical Design [6].

In colder regions where frazil ice accumulation is a problem, it may be cost effective to take

steps in preventing ice buildup. One approach is to install air bubblers or water circulating

pumps at the bottom of the racks providing a thermal change of water temperature. Another

approach is to alter the conductivity of the trash racks through replacement or modification.

Installing non-conductive racks (HDPE or FRP) can usually solve the problem. If metal racks

are used and they project above the surface of the water, a physical non-thermal conducting

break can be installed just below the water surface. This will prevent below freezing

temperatures from being transferred into the water through the trash rack. Electrically heating

the bars has also been used to prevent ice buildup, but the cost of doing so has not been

proven effective or economical [3].

―The main problem with trash removal is that it can be labor intensive. All improvements or

upgrades to the trash raking system that can help reduce costs and improve generation output

should be considered [3].‖ An estimated 5% to 25% increase in power production can be

seen with the addition of a custom engineered trash cleaning system, and the cost of these

upgrades is usually justifiable [7]. The efficiency gained can be quite significant [5]. One

utility determined that $500,000 per year could be recovered from trash-related problems at

one of their ―smaller‖ plants‘, and $250,000 per year at one of their ―larger‖ plants [7]. There

is a variety of trash rake systems currently available on the market (Figure 6). These systems

range in size as well as level of automation, so they are applicable to almost every plant

situation. The systems can be set to clean continuously, at a set interval, and/or whenever

differential head reaches a specified level. Conveyor systems can also be installed to reduce

the cost of trash removal (Figure 7). Due to the variety of trash rake options on the market,

each plant must evaluate the type of rake that will benefit them the most. ―Prior to selecting a

particular type of rake or manufacturer, the owner needs to consider the physical location of

the machine, the type of trash to be handled, and the complexity of the design and system

used to run the trash rake [3].‖


Rev. 1.0, 12/21/2011 14

Figure 6: Trash Rake System (courtesy of

Alpine Machine Co.)

Figure 7: Trash Rake Conveyer System (courtesy of

Atlas Polar Co.)

Surface roughness in the intake can contribute to head loss. Since the intake structure is a

relatively short portion of the water flow system, frictional head losses at the intake are

usually insignificant, unless the surface profile has been extensively altered or deteriorated.

The loss due to friction will increase as the intake walls roughen from cavitation or erosion in

high flow areas. Cavitation frequently causes severe damage to concrete or steel surfaces and

it may occur at sluice entrances and downstream from gate slots. Surface erosion resulting

from debris is sometimes mistaken for cavitation, and cavitation damage may be difficult to

determine from examination of the surface within the damaged area. Debris erosion may be

identified by grooves in the direction of flow. For both causes, a potential upgrade on an

intake having significant surface roughness or pitting would be to apply an epoxy concrete or

cementitious repair mortar to the concrete surface. A wide range of these repair mortars are

available having high bond strength and excellent workability likely to suit any concrete

intake surface. In the case where damage has already occurred, metal-liner plates can be used

to protect the concrete from the erosive action of cavitation. For heads above 150 feet, these

liner plates should extend five feet downstream from the gate and should not terminate at a

monolith joint or transition [10].

Another product that may be effective at reducing head loss at intakes is silicone based

coatings used to prevent organic growth. This product also provides a very smooth surface on

top of deteriorated areas on the interior intake surfaces. This coating system can be

considered in lieu of repair mortar and liner plates in most cases. The potential upgrade to

decrease the friction loss of an intake by applying a repair mortar, liner plate, or coating

system is highly dependent on accessibility and will vary on a site-specific basis.

Intakes can also introduce head loss to the system through geometric changes in the intake

wall structure. Intake walls may have slots to accommodate vertical gates or stoplogs. While

the plant is generating power and the stoplogs or gates are removed or raised, these slots

present irregular surfaces for flowing water. The void space of these slots will create minor

losses due to shape change. If the gates are not used as emergency closures in the conveyance


Rev. 1.0, 12/21/2011 15

system, slot fillers can be used to significantly reduce these losses. Slot fillers are often steel

or aluminum frames that fit snug inside the slots providing a smooth surface for flowing

water.

Other water conveyance issues that can negatively impact plant performance include valve

issues, restrictions in discharge channels, and sedimentation. Each of these issues affect

efficiency in proportion to the amount of head loss introduced to the conveyance system.

Efficiency can be gained by utilizing low-loss valves, such as gate valves, rather than higher-

loss butterfly valves. Additionally, a partially open valve will cause more loss than a fully

open valve. Therefore, care must be taken to ensure all valves are completely open when the

system is in operation.

Restrictions in discharge channels, such as weirs and bridge piers, can cause water to back up

behind them, increasing back pressure on the generation units and decreasing net available

head. The location of these structures plays a critical role in whether plant performance is

affected. Therefore, it is important to identify potential effects on generation when

considering the installation of such a structure. Additionally, natural obstructions

downstream from the dam, such as debris build-up or beaver dams, can cause similar

decreases in hydroelectric production. Care should be taken to maintain a clear discharge

channel, free of any major obstructions.

Plant efficiency can also be adversely affected by sedimentation in the reservoir behind the

dam. Upstream bed sedimentation can partially block an intake, reducing the effective flow

area and increasing the intake velocities, causing increased head loss at the intake. This issue

could be remediated by occasional dredging of the reservoir immediately upstream of the

dam.

4.0 Metrics, Monitoring and Analysis

4.1 Measures of Performance, Condition, and Reliability

Determination of the Potential Performance Level (PPL) typically requires reference to new

trash rack design information from vendors to establish the achievable unit loss

characteristics of replacement racks.

The Current Performance Level (CPL) is described by an accurate set of unit loss

characteristics determined by unit testing/monitoring.

The Installed Performance Level (IPL) is described by the unit loss characteristics at the time

of commissioning. This condition is used to determine the reference values in the

calculations detailed in this best practice. These characteristics may be determined from

vendor information and/or model testing conducted prior to or during unit commissioning.

The CPL should be compared with the IPL to determine decreases in trash rack efficiency

over time. Additionally, the PPL should be identified when considering plant upgrades. For

quantification of the PPL with respect to the CPL, see Quantification for Avoidable Losses

and/or Potential Improvements – Integration: Example Calculation


Rev. 1.0, 12/21/2011 16

4.2 Data Analysis

The key measurements for a generating unit N include:

ΔHN – Head differential across the trash rack (ft)

ΔHRN – Reference head differential across the trash rack (ft)*

QN – Unit flow rate (cfs)

– Specific weight of water (62.4 pcf)

T – Measurement interval for ΔHN (hr)

ME – Market value of energy ($/MWh)

EAN – Actual energy generation (MWh)

ERN – Reference energy generation (MWh)* *Reference values are found when the trash rack for a given unit is in its original (clean) state

Measurements can be near real-time or periodic (hourly, daily, weekly, monthly) depending

on the site details.

4.3 Integrated Improvements

Utilization: Key Computations

Avoidable power loss PN (MW) associated with ΔHN:

PN = QN (ΔHN - ΔHRN)/(737,562)

where 737,562 is the conversion from pound-feet per second to megawatts

Avoidable energy loss EN (MWh) associated with ΔHN:

EN = PNT

Avoidable revenue loss RN ($) associated with ΔHN:

RN = MEEN

Avoidable loss efficiency, Leff,N (%)

Leff,N = (EAN/ERN)100

Note that the costs associated with a trash cleaning operation should be established for

comparison with the associated revenue losses and used to schedule cleaning, to evaluate and

justify new cleaning equipment or trash rack re-design, etc.

Integration: Example Calculation

A theoretical hydroelectric plant has a steel trash rack that has become clogged over time.

The hydraulic properties of the trash rack are as follows:

Head loss across clogged trash rack = 4.0 ft

Head loss across clean trash rack = 0.5 ft


Rev. 1.0, 12/21/2011 17

Average flow across trash rack = 800 cfs

The avoidable power loss can be calculated as:

ΔP = (800 cfs)(62.4 pcf)(4.0 ft – 0.5 ft) / 737,562 = 0.24 MW

At an estimated market value of energy of $65/MWh, and assuming the plant produces

power 75% of the time, the market value of power loss can be calculated as:

0.75 (0.24 MW)($65/MWh)(8,760 hours/year) = $102, 500/year

This analysis indicates a significant avoidable energy and revenue loss over the performance

assessment interval.

5.0 Information Sources: Baseline Knowledge:

The United States Army Corps of Engineers, Debris Control at Hydraulic Structures in Selected

Areas of the United States and Europe, CHL-CR-97-4, December 1997.

Jones, R. K., P. A. March, D. B. Hansen, and C. W. Almquist, ―Reliability and Efficiency

Benefits of Online Trash Rack Monitoring,‖ Proceedings of Waterpower 97, August 1997.

American Society of Civil Engineers, Civil Works for Hydroelectric Facilities: Guidelines for

Life Extension and Upgrade, 2007.

Hydro Life Extension Modernization Guides: Volume 1 – Overall Process, EPRI, Palo Alto, CA:

1999. TR-112350-V1.

March, P. A., and P. J. Wolff, ―Component Indicators for an Optimization-Based Hydro

Performance Indicator,‖ HydroVision 2004, Montréal, Québec, Canada, August 2004.

State of the Art:

American Society of Mechanical Engineers, The Guide to Hydropower Mechanical Design,

Kansas City, Missouri: HCI Publications, July 1996.

EPRI, Hydropower Technology Roundup Report: Trash and Debris Management at

Hydroelectric Facilities, TR-113584-V10, March 2007.

EPRI, Remotely Operated Vehicle (ROV) Technology: Applications and Advancements at

Hydro Facilities, TR-113584-V7, December 2002.

VideoRay, ―US Bureau of Reclamation Reports Immediate Success with VideoRay Pro 4 ROV,‖

April 13, 2011, Retrieved from http://www.videoray.com/stories/278-us-bureau-of-reclamation-

reports-immediate-success-with-videoray-pro.

Radhuber W., ―Trash Rack Cleaning – The Past-The Present – The Future,‖ 15th

International

Seminar on Hydropower Plants, Vienna 2008.

http://www.videoray.com/stories/278-us-bureau-of-reclamation-reports-immediate-success-with-videoray-pro

http://www.videoray.com/stories/278-us-bureau-of-reclamation-reports-immediate-success-with-videoray-pro


Rev. 1.0, 12/21/2011 18

Benson B., J. Blasongame, B. Chu, J. Richter and D. Woodward, ―Aging Plants – Time for a

Physical‖: Conducting a Comprehensive Condition Assessment and the Issues Identified,‖

HydroVision 2008.


Penstocks and Tunnels

Revision 1.0, 12/06/2011

HAP – Best Practice Catalog – Penstocks and Tunnels

Rev. 1.0, 12/21/2011 20

Contents

1.0 Scope and Purpose …………………………………………………………...………….21

1.1 Hydropower Taxonomy Position ................................................................................... 21

1.1.1 Components........................................................................................................................... 21

1.2 Summary of Best Practices ............................................................................................ 24

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ................................... 24

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ................................. 24

1.3 Best Practice Cross-references ....................................................................................... 25

2.0 Technology Design Summary…………………………………………………………... 25

2.1 Material and Design Technology Evolution .................................................................. 25

2.2 State of the Art Technology ........................................................................................... 26

3.0 Operation and Maintenance Practices………..…………………...………...………… .. 27


3.2 Operations ...................................................................................................................... 28

3.3 Maintenance ................................................................................................................... 29

4.0 Metrics, Monitoring and Analysis………………………………...………..…………....33

4.1 Measures of Performance, Condition, and Reliability ................................................... 33

4.2 Data Analysis ................................................................................................................. 34


5.0 Information Sources:…..……………………………...…………………….……………35


Rev. 1.0, 12/21/2011 21


This best practice for penstocks, tunnels, and surge tanks addresses how innovations in

technology, proper condition assessments, and improvements in operation and maintenance

practices can contribute to maximizing overall plant performance and reliability. The primary

purpose of a penstock or tunnel is to transport water from the intake and deliver it to the

hydraulic turbine in the powerhouse. Once the water has been delivered to the turbine, it is then

released downstream into the discharge channel.


Hydropower Facility → Water Conveyances → Penstocks, Tunnels, & Surge Tanks

1.1.1 Components

Penstocks: Penstocks are pressurized conduits that transport water from the first free

water surface to a turbine. Penstocks can be either exposed or built integral with the dam

structure as shown in Figure 1. Characteristics of functional penstocks are structural

stability, minimal water leakage, and maximum hydraulic performance. Specific features

of a penstock system include:

Main Shell Material: Typically penstock shells are constructed of large round

steel cross-sections. Fabricated welded steel is generally considered to be the

better option when dealing with larger heads and diameters; however, pre-stressed

or reinforced concrete, glass-reinforced plastic (GRP), and PVC plastic pipes are

also utilized.

Shell Linings and Coatings: The protective membrane applied to the interior

(linings) and exposed exterior surfaces (coatings) which provide corrosion

protection and water tightness.

Connection Hardware: Includes rivets, welds, bolts, etc.

Unrestrained Joints: Includes expansion joints or sleeve-type couplings spaced

along the penstock span to allow for longitudinal expansion of the pipe due to

changes in temperature.

Air Valves: The primary function of air valves is to vent air to and from the

penstock during both operating conditions and watering/dewatering of the

penstock.

Control Valves: Includes bypass, filling, shutoff valves, and gate valves used

during watering and dewatering, redirecting flows, emergency shutoff, etc [2].

Manholes and Other Penetrations: Includes items directly attached to the penstock

and exposed to the internal pressure such as manholes, air vents and, filling line

connections.


Rev. 1.0, 12/21/2011 22

Above Ground Supports: Includes saddles, ring girders, and anchor/thrust blocks

which are susceptible to settlement or movement. The shell material and exterior

coating are also more likely to experience premature failure at support locations

due to high stresses and surface irregularities and should be periodically

inspected.

Surrounding soil backfill or concrete encasement for below ground structures.

Appurtenances: Includes transitions, bends, tees, elbows, and reducers.

Appurtenances are especially susceptible to excessive vibrations, aging, and

lining loss.

Dewatering Drains: Drains located typically at low points along the penstock span

used during dewatering. Since drains are prone to blockage or leakage, regular

inspection and cleaning of drains should be implemented [2].

Instrumentation: Any instrumentation associated with water conveyance

components such as penstocks and tunnels. This can include pressure relief

systems, emergency gate control system, and valve operators.

Figure 1: Exposed Penstocks at the Appalachia Hydroelectric Plant, Polk County, Tennessee


Rev. 1.0, 12/21/2011 23

Figure 2: Penstock Integral with Dam Structure

Tunnels: Tunnels are underground passageways commonly in rock used to carry water

for power between two points. A typical arrangement is to convey water for power in a

tunnel at low head, followed by a transition to a steep penstock to the powerhouse, with

surge handled in a surge tank at the transition. A tunnel can be pressurized or

unpressurized. Unpressurized tunnel flow is similar to open channel flow. This document

addresses tunnels with pressurized flow. Depending on the condition of the surrounding

rock or available tunneling technology, tunnels can be lined with concrete, shotcrete, or

unlined. Different linings and rock conditions will determine the amount of water leakage

and head loss through tunnels.

Surge Tanks: The surge tank is an integral part of the penstock system whose purpose is

to help provide plant stability and minimize water hammer by limiting the rise and fall of

pressure within the penstock. Surge tanks are also used to help regulate flow and

improve turbine speed regulation. There are two categories of surge tanks: conventional

open surge tank and closed air cushion surge chamber. The open surge tank can have

various shapes (horizontal area as a function of elevation) and overflow arrangements.

Any space that may be temporarily occupied by water during transient operation should

be regarded as a surge tank (e.g. aeration pipe, gate shaft, access shaft). The air cushion

chamber can reduce the total volume of the tank and can be designed for less favorable

topographic conditions; however, maintenance may be needed for compressed air

compensation. Surge tanks are typically excavated underground and lined with steel

plate, wood, or reinforced concrete. They experience issues similar to that of penstocks

such as deterioration or corrosion of tank material, breakdown in coatings and linings,

and damage or deterioration to tank mechanical appurtenances. Figure 3 shows an

example of a surge tank erected on the ground surface.


Rev. 1.0, 12/21/2011 24

In some hydropower stations, the tailrace also consists of pressurized tunnels with or

without surge tanks.

Figure 3: Steel Surge Tank at Isawa II Power Station in Japan


1.2.1 Performance/Efficiency & Capability - Oriented Best Practices

Routine monitoring and recording of head loss through penstocks and tunnels.

Trend head loss through penstocks and tunnels, comparing Current Performance

Level (CPL) to Potential Performance Level (PPL) to trigger feasibility studies

of major upgrades.

Maintain documentation of Installed Performance Level (IPL) and update when

modification to components is made (e.g. replacement of lining or coating,

addition of slot fillers).

Include industry acknowledged ―up-to-date‖ choices for penstock and tunnel

component materials and maintenance practices to plant engineering standards.

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices

Develop a routine inspection and maintenance plan.

If the exterior surface of the penstock is not already coated, provide exterior

coating to protect penstock shell and extend life.

Routinely inspect exterior supports or anchor blocks for signs of settlement or

erosion. Misalignment of the penstock could also indicate slope stability issues

or settlement.

Regularly inspect joints for leakage, corroded or missing rivets or bolts, cracked

welds and for concrete penstocks deterioration of waterstops or gaskets.

http://upload.wikimedia.org/wikipedia/commons/6/66/Isawa_II_power_station_surge_tank_and_penstock.jpg


Rev. 1.0, 12/21/2011 25

If build-up within the penstock is present, recommend high-pressure cleaning.

If organic build-up is a persistent problem, recommend replacing liner with a

fouling release type product.

Repair/replace interior liners as required to prevent shell corrosion and extend

the penstock shell life.

Routinely inspect tunnels for signs of erosion or leakage.

Water hammer or transient flow is an unavoidable and critical issue in any

pressurized water conveyance system. Water hammer can result from any load

variations, load rejections, operating mode changes, unit startup and shutdown,

and operational errors. Water hammer and transient flow can cause major

problems ranging from noise and vibrations to pipe collapse and total system

failure. Therefore, water hammer protection devices such as surge tanks, air

chambers, air valves, and pressure relief valves should be routinely inspected to

ensure they are functioning properly. In addition, flow and load control devices

such as the governor, turbine wicket gates, and penstock control valves should

be routinely checked to prevent water hammer incidences. If found to be

suspicious, measurements and further investigation should be immediately

performed.

1.3 Best Practice Cross-references

Civil – Trash Racks and Intakes Best Practice

Civil – Leakage and Releases Best Practice

Civil – Flumes/Open Channels Best Practice

Civil – Draft Tube Gates Best Practice



Coatings and linings for penstocks provide protection for the shell material and are critical to

the performance and longevity of the penstock [6]. Coating and lining technology has rapidly

evolved in recent years. Penstocks in many hydroelectric facilities have not been re-lined in

several years or have only applied local repairs to the original linings. For this reason, it is

crucial that plants perform routine evaluations as to the condition of both linings and coatings

so as to avoid costly repairs or loss of revenue due to unscheduled shutdowns.

Historically, coal tar liners have been used to line the interior of penstocks. From the 1800‘s

to 1940 a molten coal tar was used with a 15 to 20 year expected life span. However, these

liners became brittle with time which led to cracking. Coal tar enamels became readily used

after 1940 with an expected life span of 20 to 30 years. These liners were discontinued after


Rev. 1.0, 12/21/2011 26

the 1960‘s due to health and environmental concerns over high Volatile Organic Compound

(VOC) levels. Between 1960 and 1980, coal tar epoxies were used; however, due to thinner

applications, these liners had only a 15 year life span. It was not till the 1980‘s that high

performance 100% epoxies were used (25 to 30 year life expectancy) [5]. Innovations in

epoxy liners are rapidly evolving. Liners were originally used only to provide corrosion

protection and water tightness; however, recent innovations in silicone and epoxy liners can

provide resistance to build-up due to organic growth, reduction in frictional resistance, and

an increase in water flow rate performance. Also, newer liners have longer life expectancies

and limit costly maintenance or repair expenses.

Tunneling technology has also evolved over the last decades. In the 1950‘s most pressurized

tunnels and shafts were steel lined. Today, there are specialized techniques and design

concepts for unlined, high-pressure tunnels, shafts, and air cushion surge chambers which

have been developed and well-practiced in Europe and China. The cost of lining a meter of

tunnel is often two to three times the cost of excavating the tunnel; therefore, new tunneling

technology significantly saves in cost and construction time. This allows for the design of a

larger cross-sectional area of tunnel with lower flow velocity. Larger tunnels are more

tolerant of falling rocks and minor blockage along the tunnel floor given there is a rock trap

at the end of the headrace tunnel. This trade-off in tunnel design and construction may not

increase the head loss or leakage; however, the condition of the tunnel should be routinely

inspected to prevent serious collapses or local tunnel blockages.


Penstocks are pressurized conduits designed to transport water from the first free water

surface to the turbine with maximum hydraulic performance. By using state of the art

technology for new liners such as silicone-based fouling release systems, the surface

roughness of the penstock interior can be reduced (i.e. minimize frictional resistance) and

organic buildup can be limited thus reducing head loss through the system. Advancement in

computer modeling technology has also yielded more accurate penstock designs for

hydrodynamic loading limiting head loss, reducing water hammer effects, and extending life

expectancy of both liners and shell material. In addition computer modeling allows for more

accurate design for updated seismic criteria per modern building codes.

It is important to periodically collect performance data on penstocks, tunnels, surge tank and

associated components. Instrumentation technology is rapidly evolving and improving in

accuracy and reliability. By using state-of-the-art technology, hydroelectric facilities can

monitor pressure levels, movement, flow, temperature, stress, and strain. These

measurements can alert plant personnel to any changes in performance levels or required

maintenance. Also reliable performance data can be used to determine upgrade or

modernization opportunities for water conveyance systems such as penstocks and tunnels.


Rev. 1.0, 12/21/2011 27

State of the art tunneling technology allows for a larger excavation volume which reduces the

flow velocity and thus reduces hydraulic head losses. The innovative containment principles

and permeability control measures (e.g. grouting) used in tunnel design and construction can

minimize water leakage through the rock mass.



Since penstocks, tunnels, and surge tanks are exposed to occasional severe service conditions

and are expected to perform reliably for extended periods of 50 years or more, they are prone

to the following maintenance issues:

Deterioration of linings and coatings

Corrosion/thinning of steel penstock shell and other steel components

Leaking at joints/couplings

Erosion or cavitation

Organic growth on interior surfaces

Localized buckling

Air vent blockage or pressure relief valve malfunction

Foundation settlement

Slope instabilities

Sedimentation

Condition assessments of penstocks, tunnels, and surge tanks are conducted primarily by

visual examination and physical measurements. The purpose of these inspections is to

determine structural integrity, life expectancy, and necessary improvements of the

conveyance components. Most parts of these components will be difficult to inspect.

Typically, the interior inspections will require dewatering and will present a hazardous

working environment, with poor ventilation, slippery surfaces, and steep inclines. Inspection

of some components may require the use of divers or remote-controlled video equipment

(e.g., remote-operated vehicles, or ROVs). If a penstock is buried or integral with the dam

structure, an exterior inspection is not possible. Where exposed, the penstock exterior should

be inspected during full operating pressure to detect any leakage [9]. Visual inspection

typically includes assessments of corrosion, coatings, rivets/joints, general alignment,


Rev. 1.0, 12/21/2011 28

foundation conditions, and stability of supporting and adjacent earth slopes. Non-destructive

examination (NDE) testing, which should be performed on penstocks where accessible,

includes shell thickness measurements and dimensional measurements for alignment,

ovalling, and bulging. Additionally, concrete structures must be inspected for excessive

cracking and pitting. Baseline crack maps should be prepared so that new or worsened

conditions can be observed and documented [1].

It is important to schedule routine and thorough inspections of all penstock, tunnel, and surge

tank components. This will help identify any defects or other maintenance issues. Through

proper inspection, any unscheduled shutdowns for maintenance or repair can be minimized.

When developing an inspection program, an important step in the planning phase is to

acquire critical design and operating histories. This can include, but is not limited to, the

initial design criteria, geotechnical/foundation information, as-built drawings, construction

information, operation history, and records of previous maintenance issues [5].

Once a comprehensive history of the penstock, tunnel, and surge tank performance has been

acquired, personnel can develop an inspection plan. A schedule should be implemented to

periodically monitor maintenance issues. These inspections should be conducted at least once

every five years [2].

Several factors can affect how often inspections of penstocks and tunnels should occur,

including age, accessibility, public safety or environmental concerns, construction, and

previous maintenance problems [2]. An efficient and comprehensive inspection plan, specific

for each facility, should be developed after carefully considering all contributing factors. As

previously noted, inspections of penstock and tunnel components generally require

dewatering of the system. Therefore, inspections would ideally occur during scheduled unit

outages to minimize system down time. See Tables 2-1 and 2-2 in Steel Penstock – Coating

and Lining Rehabilitation: A Hydropower Technology Round-Up Report [5] for additional

guidance in developing an inspection program.

3.2 Operations

Periodic flow measurements should be obtained to determine that the water conveyance

system is functioning optimally. It is also important to routinely monitor changes in pressure

within the water conveyance system.

Performing a hydraulic transient analysis consists of computer simulation of the water

conveyance system and turbine-generator units to calculate pressure at all critical locations in

the system [2]. The maximum operating pressures within the system can be determined

through load rejection testing. Testing should be performed for a full range of operating

conditions. The scope of measurement during the transient testing should include continuous

records for the following:


Rev. 1.0, 12/21/2011 29

Pressures at the chosen points along the tunnel, penstock, immediately upstream and

downstream of the turbine, and along the outlet tailrace tunnel;

Pressures within the turbines: spiral case, head cover, under runner, and in the draft

tube;

Wicket gate openings;

Angles of runner blades for the Kaplan turbines;

Strokes of penstock control valves;

Speed of turbine units;

Torques acting on the coupling;

Axial hydraulic thrust;

Displacement and vibration of bearings.

The recorded data is very important for transient investigation and analysis. In addition, the

following parameters are to be recorded intermittently during steady-state operations before

and after transient conditions. Note that these values should agree with the corresponding

values recorded continuously.

Water levels in head reservoir and tailrace;

Wicket gate openings and angle of runner blades for Kaplan turbines;

Pressures in penstock, upstream and downstream of the powerhouse, and the tailrace

tunnel;

Pressures within the turbines: spiral case, head cover, under runner, and in the draft

tube;

Electric current and voltage in the generator;

Angular speed of turbine units.

When observed and computer simulated values fit well with each other, the program of

measurements and investigations could be shortened or revised. By determining the

maximum and minimum operating pressures, a comparison to the original system design can

be made which can help to identify significant operational changes and potential upgrade

needs.

In addition, it is important to ensure that the penstock emergency gates are functioning

properly, i.e. gates open and close freely with no binding or leakage. Emergency gate tests at

balanced head should be performed on an annual basis and every 5 to 10 years for


Rev. 1.0, 12/21/2011 30

unbalanced head. Opening/closing times and operating pressure should be recorded for future

testing comparison [2].

During plant operations, it is important to routinely inspect the exterior surfaces of penstocks

for signs of leakage while penstock is under hydrostatic pressure. If any leaks are discovered,

the source should be promptly identified and repair performed. Leakage not only increases

head loss over time, it may be indicative of more severe issues such slope instability,

foundation movement, penstock misalignment, severe corrosion, or joint failure.

3.3 Maintenance

Penstocks and tunnels carry water from the intake to the generator and introduce head loss to

the system through hydraulic friction and geometric changes in the water passageway such as

bends, contractions, and expansions. Reduction of these losses through upgrades or

replacement can improve plant efficiency and generation. However, because of the relatively

small available efficiency improvements, these actions are unlikely to be justifiable on the

grounds of reducing head losses alone [8]. Therefore, upgrading or replacing penstock and

tunnel structures will typically be economically viable only if the plant is already scheduled

for a shutdown to address other related improvements or maintenance concerns.

Although upgrades to penstocks and tunnels will have a minor effect on generation

efficiency, maintenance and life-extending repairs of these structures are very important.

Since any unscheduled repair generally requires dewatering of the system with subsequent

loss of power production, any plant shutdowns to repair penstock and tunnel structures will

have a significant effect on plant availability and generation.

Evaluating head loss in penstocks and tunnels can point to ways of increased plant efficiency.

Head loss can be caused by joints and bends, changes in diameter, and roughness and

irregularities of conveyance structures. The geometry of a penstock or tunnel structure is not

easily modified. Therefore, decreasing head losses by removing or reducing the number of

existing joints and bends is not usually an economically viable undertaking. However, if

replacement of a penstock or tunnel structure is required for other maintenance reasons, a

detailed evaluation of rerouting the waterway to increase efficiency would be warranted. In

this case, the penstock or tunnel material and diameter should also be a design consideration.

Friction Factors for Large Conduits Flowing Full [3] gives Darcy friction factors for

different conduit materials and construction types as a function of Reynolds number (Re).

These friction coefficients are directly proportional to the total frictional head loss.

Therefore, if replacement is required, selection of lower friction material and construction

types would be integral in reducing head loss through the penstock or tunnel structure. Head

losses are also proportional to the square of the velocity, so the appropriate diameter should

be verified. This is particularly important at older facilities where the hydraulic capacity

requirements of the penstock or tunnel structure may have changed over time.


Rev. 1.0, 12/21/2011 31

The internal surface roughness of penstocks contributes to head loss and can often be reduced

to yield an increase in efficiency. ―In one plant studied where the penstock is 130 feet long a

net gain of head of 0.65 feet could be realized by replacing the riveted penstocks with welded

steel, spun-tar lined penstocks. The generation gain would be more than one million kWh per

year [8].‖ Surface roughness reductions can also be achieved by coating the inside of the

penstock. Many different coating materials are available and the use of a specific material

type will be dependent on project-specific needs. Some coatings not only improve surface

roughness but can also prevent organic buildup. These coatings, such as silicone-based

fouling release systems, should be considered where bio-fouling is a design consideration.

Surface roughness may also be reduced by scrubbing and cleaning the interior of the

penstock, removing buildup of foreign material such as invasive zebra mussels as shown in

Figure 4. In one study, the surface roughness of two identical steel conduits was examined.

One conduit surface was considered ―quite smooth‖ while the other had accumulated

significant organic buildup. The average Darcy friction factors under normal operating

conditions were calculated at 0.13 for the smooth pipe and 0.20 for the pipe with buildup [3].

By restoring similarly affected penstocks to their original surface conditions, plant operators

could expect comparable results, possibly reducing friction head losses by up to 35%, as in

the case study.

Figure 4: Invasive Zebra Mussels on Steel Surface

Head loss in tunnels can be caused by similar hydraulic phenomena that affect head loss in

penstocks such as sharp bends in routing, variations in diameter, and surface roughness of the

tunnel wall. Tunnels can be both lined and unlined, and the roughness of the wall ―relative to

its cross-sectional dimensions is fundamental to the efficiency with which it will convey


Rev. 1.0, 12/21/2011 32

water [10].‖ Typical causes of head loss in tunnels that have the potential for efficiency

upgrades include rock fallout in unlined tunnels, significant and abrupt changes in rock

tunnel diameter, and organic buildup. ―Slime growth in tunnels can be a serious

problem…one plant is on record as losing 3% of maximum power due to this [8].‖ It should

be noted that by relieving one problem, others may emerge. Removing organic buildup can

expose rough linings or rock walls that have comparable head loss characteristics. Perhaps

the best technique for improving efficiencies in tunnels is to decrease surface roughness by

either filling in large cavities in the rock wall with grout or installing some type of lining. ―A

major modification for substantial reduction in head loss is the installation of concrete lining

(or to a lesser extent a paved invert) in a formerly unlined tunnel [8].‖ Lining or grouting the

tunnel wall can result in an increase in efficiency by reducing leakage into the surrounding

rock which can reduce the available generation flow.

Penstock shell thickness measurements need to be taken and monitored periodically to

identify losses in thickness, which must then be compared with minimum acceptable

thickness values. If shell thinning exceeds acceptable values for structural integrity,

corrective actions must be taken [9]. Deteriorated penstocks may be rehabilitated by patching

at localized areas of need, lining with a material such as fiberglass to reinforce the structure

of the penstock, or replacing the existing penstock [7].

Figure 5: Exposed Portion of Penstock at Center Hill Hydro Plant in DeKalb Co., Tennessee

Another concern for penstock structural integrity is ovalization or out-of-roundness due to

improper installation or design. If this occurs, the penstock diameter should be measured at

various locations along its length and recorded to help monitor any geometric changes. Other


Rev. 1.0, 12/21/2011 33

possible structural problems that must be carefully monitored include penstock alignment,

pinhole leaks, and localized shell buckling. Additionally, it is important to carefully inspect

the shell liner for protrusions, caused by organic growth, marine organisms (e.g., mussels),

and degradation of the linings or coatings – all of which can impede water flow [2].

Ultrasonic devices can be utilized for determining shell thickness and rivet integrity. There

have also been advances in remote-controlled video equipment (e.g., ROVs) for use in

inspections of penstocks and intakes where access is limited that allow for safe and efficient

inspections. Portions of penstocks that cannot be dewatered or readily dewatered should be

periodically inspected by a diver or an ROV. For more information on non-destructive testing

methods see Steel Penstocks [9].

After the inspection, an evaluation should be done to determine if corrective actions need to

be taken and what is the best way to implement them. The evaluation of penstock and tunnel

components should be performed by a qualified individual or team to determine the system‘s

reliability to perform per the original design criteria and to make recommendations for future

inspection frequency and areas of focus.

The key to improving system performance through penstock and tunnel component

rehabilitation can be summarized as follows: 1) Development of an inspection/maintenance

program based on individual system needs; 2) Effective implementation of the inspection

program; 3) Proper evaluation of inspection results; 4) Recommendations for rehabilitation

and repairs with focus on efficiency improvements and service life extension; and 5)

Execution of upgrades and repairs with limited system shutdown time. Establishing a proper

maintenance program can reduce the occurrence of unscheduled shutdowns and efficiency

losses in penstock and tunnel components.



The fundamental equations for evaluating efficiency through penstocks and tunnels is the

Darcy-Weisbach equation for head loss due to friction and the equation for head loss due to

minor losses from geometric irregularities such as gate slots and bends. Avoidable head

losses can be directly related to overall power/energy loss and subsequent loss of revenue for

the plant. These equations are defined as follows:

Avoidable head loss due to friction, Δhf (ft), from the Darcy-Weisbach equation:

Where: · Δf is the difference in Darcy friction factors computed for the existing

roughness conditions and roughness conditions after potential upgrade

· L is the length of the conveyance component (ft)


Rev. 1.0, 12/21/2011 34

· V is the average flow velocity or flow rate per cross-sectional area (ft/s)

· D is the hydraulic diameter (ft)

· g is the acceleration due to gravity (ft/s2)

Avoidable head loss due to minor losses (e.g., gate slots), Δhm (ft):

Where: · ΔK is the difference in minor head loss coefficients computed for existing wall

irregularities from gate slots and for conditions with irregularities removed by use

of slot fillers after potential upgrades.

· V is the average flow velocity or flow rate per cross-sectional area (ft/s)


Other key values required to complete the computations for avoidable head losses include the

dimensionless Reynolds number, Re, Darcy friction factor, f, kinematic viscosity, v (ft2/s),

and equivalent roughness ε (ft). If the Reynolds number and relative roughness of the

penstock shell or tunnel interior are known, the Darcy friction factor can be determined using

either the Moody diagram or the associated Colebrook-White equation. If exact relative

roughness measurements are unavailable, an approximate Darcy friction factor can be

determined by comparing the existing conditions with charts found in publications such as

Friction Factors for Large Conduits Flowing Full [3], which provide data of measured Darcy

friction factors for various construction materials.

Avoidable power loss, ΔP (MW), associated with Δhf or Δhm:

ΔP = Q γ Δh / 737,562

Where: · Q is the average volumetric flow rate through the plant (ft3/sec)

· γ is the specific weight of water (62.4 lb/ft3)

· Δh is the avoidable head loss

· 737,562 is the conversion from pound-feet per second to megawatts


Rev. 1.0, 12/21/2011 35

Avoidable energy loss, ΔE (MWh), associated with Δhf or Δhm:

ΔE = ΔPT

Where: · ΔP is the avoidable power loss (MWh)

· T is the measurement interval (hrs.)

Avoidable revenue loss, ΔR ($), associated with Δhf or Δhm:

ΔR = ME ΔE

Where: · ME is the market value of energy ($/MWh)

· ΔE is the avoidable energy loss

4.2 Data Analysis

Determination of the Potential Performance Level (PPL) will require reference to the flow

characteristics of the modified geometry and/or surface roughness of the penstock or tunnel

components. The PPL will vary for each plant. However, the maximum PPL will be based on

the flow characteristics of the most efficient available upgrade.

The Current Performance Level (CPL) is described by an accurate set of water conveyance

component performance characteristics determined by flow and head measurements and/or

hydraulic modeling of the system.

The Installed Performance Level (IPL) is described by the water conveyance component

performance characteristics at the time of commissioning or at the point when an upgrade or

addition is made. These may be determined from reports and records of efficiency and/or

model testing at the time of commissioning or upgrade.

The CPL should be compared with the IPL to determine decreases in water conveyance

system efficiency over time. Additionally, the PPL should be identified when considering

plant upgrades. For quantification of the PPL with respect to the CPL, see Quantification for

Avoidable Losses and/or Potential Improvements – Integration: Example Calculation.


The periodic field test results should be used to update the unit operating characteristics and

limits. Optimally, these would be integrated into an automatic system (e.g., Automatic

Generation Control), but if not, hard copies of the data should be made available to all

involved personnel – particularly unit operators, their importance emphasized, and their

ability to be understood confirmed. All necessary upgrades or maintenance (penstock re-


Rev. 1.0, 12/21/2011 36

lining, penstock cleaning, etc) and methods to routinely monitor unit performance should be

implemented.

Integration: Example Calculation

A theoretical hydroelectric plant has three girth-welded steel penstocks integral with the dam

structure. The interior of the penstocks has significantly corroded over time. The hydraulic

properties of each penstock are as follows:

Length = 600 ft

Diameter = 14 ft

Average flow = 2200 cfs

Average velocity = 14 ft/s

If the penstocks are treated with a silicone-based coating system, the decrease in head loss

can be calculated as follows:

Surface roughness of existing penstocks (corroded steel w/ welded girth joints) = 0.005 ft

Relative roughness of existing penstocks = (0.005 ft) / (14 ft) = 3.6 x 10-4

Surface roughness of silicone coating = 0.000005 ft

Relative roughness of silicone coating = (0.000005 ft) / (14 ft) = 3.6 x 10-7

Re = (14 ft/s)(14 ft) / (1.0 x 10-5

ft2/s) = 1.9 x 10

7

From the Moody diagram:

fexisting = 0.016

fsilicone = 0.008 → Δf = 0.016 – 0.008 = 0.008

The decrease in head loss per penstock:

Δhf = (0.008) [(600 ft) / (14 ft)] [(14 ft/s)2 / 2(32.2ft/s

2)] = 1.04 ft

The decrease in head loss in all three penstocks:

Δhf = 3 (1.04 ft) = 3.13 ft

The increase in power production can be calculated as:

ΔP = (2200 cfs)(62.4 pcf)(3.13 ft) / 737,562 = 0.583 MW


Rev. 1.0, 12/21/2011 37

At an estimated market value of energy of $65/MWh, and assuming the plant produces

power 75% of the time, the market value of increased power production can be calculated as:

0.75 (0.583 MW)($65/MWh)(8,760 hours/year) = $250,000/year

This analysis indicates an available energy and revenue increase over the performance assessment

interval.

5.0 Information Sources:

Baseline Knowledge:

Bureau of Reclamation, Veesaert, Chris J., Inspection of Spillways, Outlet Works and

Mechanical Equipment, National Dam Safety Program Technical Seminar Session XVI,

February 2007.

Bureau of Reclamation, McStraw, Bill, Inspection of Steel Penstocks and Pressure Conduits,

Facilities Instructions, Standards, and Techniques, Volumes 2-8, September 1996.

Bureau of Reclamation, Friction Factors for Large Conduits Flowing Full, A Water

Resources Technical Publication, Engineering Monograph No. 7, Reprinted 1992.

Pejovic, Boldy and Obradovic, Guidelines to Hydraulic Transient Analysis. Gower

Publishing Company, Brookfield, Vermont. 1987.

Hydro Life Extension Modernization Guide, Volume 3: Electromechanical Equipment, EPRI,

Palo Alto, CA: 2001. TR-112350-V3.

State of the Art:

Electric Power Research Institute (EPRI), Steel Penstock – Coating and Lining

Rehabilitation: A Hydropower Technology Round-Up Report, Volume 3, TR-113584-V3,

2000.

American Society of Civil Engineers (ASCE), Civil Works for Hydroelectric Facilities –

Guidelines for Life Extension and Upgrade, ASCE Hydropower Task Committee, 2007.

Kahl, Thomas L., Restoring Aging Penstocks, Hydro Review, December 1992.

Standards:

EPRI, Increased Efficiency of Hydroelectric Power, EM-2407, Research Project 1745-1,

Final Report, June 1982.

ASCE, Steel Penstocks, ASCE Manuals and Reports on Engineering Practice No. 79, 1993.

United States Army Corps of Engineers (USACE), Engineering and Design – Tunnels and

Shafts in Rock, EM 1110-2-2901, May 1997.


Rev. 1.0, 12/21/2011 38

USACE, Engineering and Design – Hydraulic Design of Reservoir Outlet Works, EM 1110-

2-1602, October 1980


Flumes and Open Channels

Revision 1.0, 12/02/2011

HAP – Best Practice Catalog – Flumes and Open Channels

Rev. 1.0, 12/08/2011 40

Contents 1.0 Scope and Purpose .................................................................................................................. 41

1.1 Hydropower Taxonomy Position ........................................................................................ 41

1.1.1 Components ................................................................................................................. 41

1.2 Summary of Best Practices ................................................................................................. 43

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ........................... 43

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices .......................... 43

1.3 Best Practice Cross-references ............................................................................................ 44

2.0 Technology Design Summary................................................................................................. 44

2.1 Material and Design Technology Evolution ....................................................................... 44

2.2 State of the Art Technology ................................................................................................ 45

3.0 Operation and Maintenance Practices ..................................................................................... 46

3.1 Condition Assessment......................................................................................................... 46

3.2 Operations ........................................................................................................................... 48

3.3 Maintenance ........................................................................................................................ 49

4.0 Metrics, Monitoring and Analysis .......................................................................................... 52

4.1 Measures of Performance, Condition, and Reliability ........................................................ 52

4.2 Data Analysis ...................................................................................................................... 54

4.3 Integrated Improvements .................................................................................................... 55

5.0 Information Sources: ............................................................................................................... 55


Rev. 1.0, 12/08/2011 41


This best practice for flumes and open channels addresses how innovations in technology and

design, proper condition assessments, and improvements in operation and maintenance practices

can contribute to maximizing overall plant performance and reliability.


Hydropower Facility

3.0 Water Conveyances

3.7 Flumes / Open Channels

3.7.1 Flumes

3.7.2 Open Channels

3.7.3 Forebay Structure

3.7.4 Desilting Chamber

1.1.1 Components

Flumes and open channels are free-flow water conveyance systems for hydroelectric

facilities. In certain hydro facilities the surface water reservoirs are not located directly

adjacent to the generating station and the topographical or geological condition is not

suitable for tunneling; therefore, necessitating the use of flumes or open channels to

divert flow from the reservoir and convey the water over long distances. The primary

purpose of flumes and open channels is to carry adequate water flows with minimized

hydraulic losses [4]. Both flumes and open channels operate under the laws of open

channel flow. The long distance open channel flow system is usually designed and

constructed for water diversion (i.e., run-of-river) scheme of hydro projects with lower

head and/or lower power capacity.

Flumes: A type of free-flow, man-made hydraulic channel generally square, rectangular,

or semicircle constructed primarily of wood, steel, concrete, or masonry. Flumes can be

supported on grade, piles, structural steel framing, concrete piers, or wood framing as

show in Figure 1. Typically flumes are costly to construct; therefore, they are generally

used to convey smaller quantities of water than open channels/canals or when the

surrounding terrain necessitates the use of flumes.


Rev. 1.0, 12/08/2011 42

Figure 1: Wood Flume (Bull Run Hydro Project, Oregon)

Open Channels: An upstream open channel is a type of free-flow water conveyance

system used to transport water from its source (river, impounded lake, etc.) to the

powerhouse, which is also referred to as intake canal, power canal, or headrace channel.

A tailrace is often designed as an open channel (i.e., tailrace channel), rather than a

tailrace tunnel, for discharging the tailwater collected from the turbines back into the

original river/lake or to other rivers downstream. Open channels differ from flumes in

that they are hydraulic channels excavated in the earth or rock (see Figure 2) whereas

flumes are generally elevated man-made structures. Open channels can be constructed in

various shapes and sizes and may either be lined or unlined.

Figure 2: Open Channel (Sir Adam Beck #1 Power Station, Niagara River, Canada)


Rev. 1.0, 12/08/2011 43

Forebay Structure: The primary function of a forebay structure is to provide limited

storage for hydroelectric facilities during operational changes. These structures are

typically sized to provide the initial water supply needed when increasing plant output

while water in conveyance components is being accelerated; as well as to accept the

rejection or surplus water due to a decrease in plant output. Forebay structures may be a

separate head pond or integral with the intake canal or open channel [4].

De-silting Chamber: A tank or chamber generally located upstream from water

conveyance systems used to trap suspended silt load, pebbles, etc. so as to minimize

erosion damage to the turbine runner.



Routine monitoring and recording of head loss through flumes and open channels.

Trend head loss through flumes and open channels comparing Current

Performance Level (CPL) to Potential Performance Level (PPL) to trigger

feasibility studies of major upgrades.


modifications to components are made (e.g., replacement of liner).

Include industry acknowledged ―up-to-date‖ choices for flume and open channel

design component materials and maintenance practices to plant engineering

standards.



Routinely inspect flume supports for signs of settlement or erosion.

Regularly inspect structural joints for leakage, corroded or missing rivets or

bolts, cracked welds, damage, etc.

Routinely clean and remove debris from flumes and open channels.

Routinely inspect and maintain debris removing systems (i.e. trash boom).

Periodically remove sedimentation by dredging, flushing, vacuum extraction, or

other available methods.

Document any operational changes such as an increase in the Probable

Maximum Flood (PMF), changes in flow requirements due to unit upgrades,

changes in seismic criteria, or changes in operational regimes to compare with

the original design criteria to ensure that the water conveyance component is

functioning optimally and safely.


Rev. 1.0, 12/08/2011 44

As compared with a headrace channel, a tailrace channel is usually shorter and

flow velocities are slower; therefore, head loss and water loss are less of a

concern. However, flow capacity and safety of tailrace operations should not be

compromised (i.e., sudden blockage of the tailrace might cause a severe

accident).


Civil – Trash Racks and Intakes Best Practice

Civil – Leakage and Releases Best Practice

Civil – Penstocks, Tunnels, and Surge Tanks Best Practice

Civil – Draft Tube Gates Best Practice



Channel liners can be used to increase the hydraulic performance of open channels and

flumes. Historically, open channels have been unlined or lined with erodible material such as

sand or gravel. Unlined channels are plagued by several operational and maintenance-related

issues such as erosion of embankment slope material, water seepage, hydraulic losses due to

frictional resistance, and loss of hydraulic area due to vegetation growth or buildup of eroded

material. Linings can improve hydraulic performance by improving discharging capacity,

reducing frictional head losses, improving operational efficiency, extending channel life

expectancy, preventing buildup due to vegetation such as weeds, reducing maintenance costs,

and reducing seepage losses [1]. There have been recent innovations in liner materials and

application processes. The use of geo-membranes has been used in recent years due to its

ease of application and water-tightness.

The US Bureau of Reclamation conducted a 10 year study of various channel lining

arrangements and their effectiveness on reducing seepage [5]. The three primary

arrangements included concrete, exposed geomembranes, and a combination of concrete with

a geomembrane under-liner. The concrete liner proved to have excellent durability; however,

the long term effectiveness of preventing seepage was poor due to cracking. The installation

and maintenance of a concrete liner is generally cost effective since plants are familiar with

concrete and better equipped to provide routine maintenance such as crack repair. Figure 3

shows an example of a canal concrete lining project. The exposed geomembrane liner proved

to be very effective in reducing or eliminating water losses due to seepage; however, they are

more susceptible to damage than concrete and have a shorter service life (15 to 20 years) [5].

Geomembranes have a lower initial installation and maintenance cost, but the long term

maintenance costs can be almost twice as much as concrete. This is due to the fact that plant


Rev. 1.0, 12/08/2011 45

personnel are generally not familiar with the material and special equipment or training may

be required for even minor repairs. The third arrangement proved to be the most effective

and easily maintained. By providing a geomembrane under-liner for the concrete lining, they

were able to achieve the desired water tightness of a membrane while still having the

durability and protection of the concrete. The maintenance costs are also lower since only

the concrete top coat requires maintenance. Other material combinations that were tested

included geosynthetics, shotcrete, roller compacted concrete, grout mattresses, soil,

elastomeric coatings, and sprayed-in-place foam [5]. The appropriate channel liner should be

addressed on an individual plant basis. Factors to consider when determining the most

appropriate liner should include plant economics (maintenance and construction expenses),

availability of local materials, local terrain limitations (use of heavy construction equipment

may not be possible), amount of excavation or subgrade preparation necessary,

environmental constraints, and desired hydraulic characteristics.

Figure 3: Coachella Canal Concrete Lining Project (Coachella County, California)


For designing a new open channel system or considering a replacement of an existing open

channel or flume when it is severely deteriorated or no longer meets the operational

requirements , computer-aided modeling can be used to develop the most efficient hydraulic

arrangement (channel shape, longitudinal slope, side slope, minimum and maximum


Rev. 1.0, 12/08/2011 46

permissible velocities, type of lining, etc.) while balancing plant economics, site specific

limitations, and construction limitations. For example, from a hydraulics stand point, the

most efficient section for open channel flow is a semicircle since for a given area it has the

least wetted perimeter than any other shape; however, a semicircle shape may not be the most

economical solution since it costs more to excavate and line the curved surface, it may not be

feasible for the available natural condition, or the arrangement may be limited by the channel

slope. The use of scaled physical models has become standard procedure in recent years for

the design of open channels. Scaled hydraulic models allow for performance to be checked

while still in the design phase. Advances in computer technology can aid in the development

of hydraulic models for testing. Both the numerical model (e.g., HEC-RAS) and physical

model should simulate the unsteady flows with wave propagation and backwater effect along

the channel under either routine or emergency plant operations. By checking performance,

any necessary design changes or modifications that could potentially result in savings in

operating and construction costs can be identified [8]. Therefore, computer-aided modeling

can be beneficial in helping to balance hydraulic efficiency with plant requirements and

economics.

In addition to advances in computer-aided modeling, construction techniques have also

advanced. Historically, channels have been trapezoidal in shape due to limitations in

constructability. As of recent years, advances in both lining and excavation techniques have

allowed for curved bottomed channels which are hydraulically more efficient [9].



Since flumes and open channels (including the forebay, de-silting chamber and tailrace

channel) are periodically exposed to severe service conditions such as turbulent water or

severe weather, they are prone to the following maintenance issues:

Erosion of channel embankment slopes

Structural deterioration

Concrete spalling (canal linings, flumes, or guide walls)

Steel corrosion (flume structural components or linings)

Increased surface roughness due to aquatic growth/vegetation and erosion

Sedimentation

Water loss due to seepage through linings, joints, embankments, etc.

Ice and debris collection or blockage


Rev. 1.0, 12/08/2011 47

Deterioration of linings

Foundation settlement or deterioration

Instability of adjacent slopes

It is important that flumes and open channels be routinely inspected for not only efficiency

related maintenance issues but also safety, since failure of a flume or channel can have dire

consequences. Condition assessments are primarily conducted by visual examination and

physical measurements. The purpose of any water conveyance condition assessment is to

determine the structural integrity of the components, the remaining life expectancy, and any

necessary upgrades to improve overall efficiency. A visual inspection typically includes

assessments of corrosion, lining deterioration, joint conditions (bolts, weld, etc.), evidence of

embankment erosion or instability, foundation conditions, stability of supporting and

adjacent earth slopes, and flow blockage due to debris or ice accumulation. Since the

interiors of flumes and open channels are often underwater and difficult to inspect, it is

recommended that when components are required to be dewatered for other reasons, the plant

should inspect the interiors and remove any debris or buildup of sedimentation. Flume

exteriors should be visually inspected for any signs of leakage while in operation.

Data records from previous inspections, maintenance, and upgrades should be obtained. By

reviewing any previous records potential problems can more easily be identified such as

worsening conditions or chronic issues. It is important to identify any previous repairs or

repair recommendations that might not have been implemented. Another key to an effective

inspection plan is to review the original design documents. This can help to identify if: 1)

obsolete construction methods were used such as copper waterstops or unlined channels, 2)

there are any obsolete components, configurations, equipment, or other features in use such

as poor hydraulic shape for channels, 3) materials are nearing the end of their life

expectancy, 4) there were any problems encountered during construction such as a fault zone

across a channel or a soft zone in the foundation material, 5) inadequate inspection during

construction, and 6) foundation issues such as geologic faults or differential settlement [3].

Plants should schedule routine and thorough inspections of all flume and open channel

components. This will help to identify defects or other maintenance issues so that

unscheduled shutdowns for repairs can be minimized. When developing an inspection

program, it is also important to acquire information regarding operational records which

should show any changes in operation or upgrades. It will allow for comparison of current

operating conditions with the original design criteria.

The frequency and extent of condition assessments will be based on various plant and site

specific factors including accessibility, age of structure or component, previous maintenance

or reliability issues, public safety or environmental concerns, changes in operation, etc. An

efficient and comprehensive inspection plan should be developed after considering all


Rev. 1.0, 12/08/2011 48

contributing factors. If significant issues are discovered during the condition assessment, then

the plant should have a qualified engineer perform a special inspection to determine what

repairs are necessary or if replacement is required. It is also recommended that plants

perform special inspections after floods, earthquakes, or any other unusual event (e.g., load

rejection) that may have resulted in damage [3].

3.2 Operations

Routine removal of debris and ice should be performed using trash/ice booms or similar. If

debris or ice buildup is a recurrent issue, it is recommended that the plant consider installing

permanent structures for aid in removal. Sedimentation can also have a negative impact on

plant operations. Sediment should be routinely removed using methods such as dredging,

vacuum extraction, flushing, mining dry while conveyance system is dewatered, or in more

severe instances the addition of a stilling basin upstream to allow settlement of sedimentation

or a sediment collection device. Also, increasing the flow velocity by reducing channel cross-

sectional area can help the flow achieve ‗flushing velocity‘; however, this is generally only a

consideration in new design. By achieving the ‗flushing velocity‘, accumulation of

sedimentation is reduced; however, the sediment is passed downstream where it might still

pose operational or maintenance issues such as turbine erosion. The addition of a de-silting

chamber can also be installed upstream to help trap suspended silt particles. Buildup of

sedimentation can increase surface roughness and reduce cross-sectional area, therefore

increasing head losses due to frictional resistance. In addition, the removal of debris or ice

buildup can increase flow. Thus routine cleaning practices can improve hydraulic

performance through water conveyance systems and increase overall plant efficiency. It is

important to note that not only does debris and ice buildup have a negative effect on

operation, they can also cause blockage and lead to failure as was the case with the forebay

skimmer wall failure at the Safe Harbor Hydroelectric Project in Pennsylvania as a result of

ice accumulation [4].

Plants should routinely evaluate any changes in the Probable Maximum Flood (PMF) from

the original design criteria. If the PMF increases, structures should be re-evaluated through

hydraulic model tests to determine that the existing conveyance system is still adequate.

Miscalculation of PMF in the original design or failure to account for changes in PMF from

recent hydrological analysis of watershed, may lead to overtopping of the canal embankment

or failure. If the structural integrity of the system is not compromised, an increase in PMF

can be addressed by raising channel embankments or constructing parapet walls; however, in

some cases construction of a new conveyance system may be necessary [4].

Another important phenomena to consider in channel operations is hydraulic jump or

hydraulic drop (fall). When high velocity flow (supercritical) is introduced to a section of

slow moving flow (subcritical) resulting in a rapid reduction of flow velocity over a short


Rev. 1.0, 12/08/2011 49

length, the channel will experience an abrupt rise in water surface known as a hydraulic

jump. Alternatively, a hydraulic drop is caused by the introduction of subcritical flow to

supercritical flow causing a rapid increase in flow velocity and abrupt drop in water surface

level. Sudden changes in channel bed slope can result in hydraulic jumps or drops.

Hydraulic jumps and drops in the intake channel can negatively affect plant efficiency by

dissipating energy and leading to head loss. Hydraulic jumps can be avoided by ensuring that

transitions at the intake channel are gradual. Alternatively, hydraulic jumps may be desirable at the

discharge when erosion in the downstream channel or river is a concern. Through hydraulic jump

basins, the discharge energy can be dissipated before flow is returned to the downstream channel

limiting erosion problems [2]. If hydraulic jumps or drops are observed, plants should consider

further investigation into how the phenomena is impacting operations and if corrective action is

warranted. Generally, this occurrence is only considered during the initial design since any upgrades

to reduce jumps or drops are not economically feasible for improving efficiency alone.

Other operational considerations include increased flow requirements due to unit upgrades,

changes in seismic criteria, changes in operational regimes, or any condition changes

unaccounted for in the original design such as degradation conditions or increased surface

roughness; as well as potential emergency circumstances (e.g., load rejection causing wave

propagation and backwater effect) when the operational regimes and conditions have been

changed. Plant personnel should routinely evaluate flumes and open channels to ensure that

they are functioning properly and efficiently for the current operational characteristics.

3.3 Maintenance

Flumes and open channels are designed to convey water from its source (river, lake,

reservoir, etc.) over a long distance to the intake or pressurized conduit (penstock or tunnel)

or discharge water from the powerhouse to the downstream river/lake, while limiting losses

due to hydraulic friction, seepage, and leakage. Reduction of these losses through installation

or repair of a liner or replacement of the conveyance system can help improve plant

efficiency and generation; however, these upgrades can be costly and not likely justifiable on

the grounds of reducing head losses alone [7]. Therefore, upgrade or replacement of a water

conveyance component such as flumes or open channels is generally only viable if safety of

the structure is a concern, the component no longer satisfies the operating requirements, there

is significant seepage or erosion, or the water conveyance has severe degradation. Since

upgrades or replacement can be costly, it is important to routinely perform any necessary

maintenance or life-extending repairs so as to limit unscheduled shutdowns which can affect

plant availability and generation.

Foundations and supports should be regularly checked for signs of seepage. Seepage is the

slow percolation of water through an embankment or foundation [3]. Seepage not only

results in loss of water it can also saturate the supporting soil and either undermine the

foundation or cause it to shift or collapse. Other foundation issues can include erosion,


Rev. 1.0, 12/08/2011 50

settlement which can lead to misalignment, foundation faults, heaving due to expansive

foundation material such as clay. Erosion and stability of surrounding slopes are also a

concern. Eroded material from surrounding slopes can cause blockages in channels or

increase the hydraulic roughness. Failure of a surrounding slope can also negatively impact

the structural integrity of flumes and channels, as was the case with the Ocoee River Flume

in Tennessee. In April 2010, a rock slide destroyed a 70 ft section of the historic wood

flume. The rock slope was stabilized using 90 bolts, some 40 ft long as shown in Figure 4

[6]. Other means of slope stabilization can include the addition of retaining structures or

shotcrete. If large amounts of sloughed materials from surrounding slopes are present in

flumes and channels, further investigation of slope stability is warranted.

Figure 4: Slope Stabilization (Ocoee River Flume, Ocoee, Tennessee)

Photo Courtesy of J. Miles Cary


Rev. 1.0, 12/08/2011 51

Figure 5: Wood Flume Repair (Ocoee River Flume, Ocoee, Tennessee)

Photo Courtesy of Jason Huffine/TVA

It is critical that any obstructions within flumes or open channels be removed promptly so

that the flow capacity is not negatively impacted. Obstructions can result from overgrown

vegetation, aquatic growth, sloughed materials from adjacent slope failures, debris such as

dead trees or limbs, or ice accumulation [3]. Obstructions such as these will not only impede

the flow capacity, but can also lead to damage of the structure or liner, increased hydraulic

roughness, or sudden failure due to blockage. Debris should be routinely removed so as to

avoid buildup.

Since flumes and open channels are often subject to turbulent flow, concrete liners,

structures, or foundations are likely to experience a range of concrete problems. These issues

include cracking, surface defects, cavitation, erosion, and leakage at joints. Concrete cracking

is a common phenomenon in hydroelectric facilities and does not necessarily require

immediate action. Cracks should, however, be routinely monitored, measured, and

documented for future comparison. It is necessary to have ongoing records documenting any

cracks so that any significant changes can be identified. If new cracks suddenly appear or

existing cracks become more severe or extensive, then further investigation by a qualified

engineer is warranted [3]. Concrete surface defects may include shallow deficiencies in the

concrete surface, textural defects from improper installation, and localized damage caused by

debris [3]. Any surface defects should be recorded and any necessary repairs performed.

Concrete deterioration due to either cavitation or erosion should be routinely monitored and

repaired as necessary. Concrete repairs can include shotcrete applications, localized grouting

of cracks, replacement or patching, or overlays for concrete liners.


Rev. 1.0, 12/08/2011 52

Water loss through joint leakage is another common issue for open channels and flumes.

Concrete channels often have waterstops which are continuous strips of waterproof material

embedded in joints, usually made of metal, PVC, or rubber [3]. When waterstops are

damaged or begin to deteriorate, water can seep through the joints. Not only does this lead to

water loss, it can also lead to erosion of the foundation material or further joint damage due

to freeze/thaw. Channel joints should be inspected when dry if possible. Evidence of joint

problems can include soil fines seeping through the joint, vegetation in joints, or damaged or

missing joint sealant [3]. Joints can be repaired by grouting, replacement of joint material or

waterstops, sealing joints with epoxy, or the addition of a watertight membrane over the

entire channel.

Figure 6: Waterstop Repair in Concrete Channel

Steel can be used for flume supporting structures, channel liners, or flume liners. Since steel

in hydroelectric facilities is repeatedly exposed to moisture, corrosion is oftentimes a

recurrent problem. Evidence of steel corrosion can include scaling, flaking, pitting, or color

changes. If left unchecked, corrosion can lead to loss of material, leakage, and in some

instances failure of the structure. Corrosion can be limited or avoided by either painting the

steel or installing cathodic protection. Other steel problems include fatigue due to repetitive

loading, erosion by abrasive debris, tearing or rupture due to debris impact, cavitation due to

high flow velocities, cracking, and deformation [3]. Plant personnel should regularly inspect

all steel surfaces for any signs of deterioration or problems.



The fundamental equations for evaluating efficiency through flumes and open channels are

Manning‘s equation for open channel flow, the equations for head losses due to friction and

geometrical changes, and water losses due to seepage, leakage, or unexpected overflow


Rev. 1.0, 12/08/2011 53

(water loss from evaporation is minimal and unavoidable) [2 and 9]. Losses due to leakages

or unexpected overflow are more difficult to quantify and require more detailed analysis

based on a plant specific basis. Avoidable head losses can be directly related to overall

power/energy loss and subsequent loss of revenue for the plant. These equations are defined

as follows:

Flow quantity, Q (ft3/sec):

Where: · Q is the flow quantity (ft3/sec)

· n is the Manning roughness coefficient

· A is the cross-sectional area (ft2)

· R is the hydraulic radius (ft)

· S is the slope of energy line or energy gradient (ft/ft)

Head loss due to friction, hf (ft):

Where: · hf is the head loss due to friction through the conveyance component (ft)

· n is the difference in Manning roughness coefficients for existing roughness

conditions and roughness conditions after potential upgrades.

· L is the length of the conveyance component (ft)

· v is the average flow velocity or flow rate per cross-sectional area (ft/sec)

· R is the hydraulic radius (ft)

Head loss due to minor losses (e.g. channel bends, adjacent slopes), hm (ft):

Where: · hm is the head loss due to minor losses from geometrical changes (ft)

· Kb is the difference in the head loss coefficient for existing conditions and for

conditions after potential upgrades computed as follows for channel bends:

· W is the channel width (ft)

· Rc is the center-line radius of the channel curve (ft)


Rev. 1.0, 12/08/2011 54

· V is the mean velocity or flow rate per cross-sectional area (ft/s)


Moritz formula for water losses due to seepage in unlined channels, S (ft3/s/mile):

Where: · S is the losses due to seepage (ft3/s/mile)

· C is the rate of water loss (ft3/24 hours/1 ft

2 of wetted area). Average values of C

can range from 2.20 for sandy soils to 0.41 for clays.

· Q is the flow quantity (ft3/s)

· V is the mean velocity (ft/s)

Avoidable power loss, ΔP (MW), associated with head losses:

ΔP = (Q γ Δh+ ΔQ γ h) / 737,562

Where: · Q is the average volumetric flow rate through the water conveyance component

(ft3/sec)


· Δh is the avoidable head loss

· 737,562 is the conversion from pound-feet per second to megawatts

Avoidable energy loss, ΔE (MWh):

ΔE = ΔPT

Where: · ΔP is the avoidable power loss (MWh)

· T is the measurement interval (hrs.)

Avoidable revenue loss, ΔR ($):

ΔR = ME ΔE

Where: · ME is the market value of energy ($/MWh)

· ΔE is the avoidable energy loss

4.2 Data Analysis

Determination of the Potential Performance Level (PPL) will require reference to the flow

characteristics of the modified geometry and/or surface roughness of the flume or open


Rev. 1.0, 12/08/2011 55

channel components. The PPL will vary for each plant. However, the maximum PPL will be

based on the flow characteristics of the most efficient available upgrade.

The Current Performance Level (CPL) is described by an accurate set of water conveyance

component performance characteristics determined by flow and head measurements and/or

hydraulic modeling of the system.

The Installed Performance Level (IPL) is described by the water conveyance component

performance characteristics at the time of commissioning or at the point when an upgrade or

addition is made. These may be determined from reports and records of efficiency and/or

model testing at the time of commissioning or upgrade.

The CPL should be compared with the IPL to determine decreases in water conveyance

system efficiency over time. Additionally, the PPL should be identified when considering

plant upgrades.



maintenance practices. Optimally, any test results or observations should be integrated into

an automated system, but if not, hard copies of the data should be made available to all

involved plant personnel (particularly unit operators). All necessary upgrades or maintenance

(channel lining, debris removal, slope stabilization, etc.) and methods to routinely monitor

unit performance should be implemented.


Baseline Knowledge:

Professor B.S. Thandaveswara, Hydraulics: Design of Canals, Indian Institute of

Technology Madras.

Bureau of Reclamation, Design of Small Dams, A Water Resources Technical Publication,

3rd

Edition, 1987.

Bureau of Reclamation, Veesaert, Chris J., Inspection of Spillways, Outlet Works, and

Mechanical Equipment, National Dam Safety Program Technical Seminar Session XVI,

February 2007.

Hydro Life Extension Modernization Guide, Volume 4-5 Auxiliary Mechanical and

Electrical Systems, EPRI, Palo Alto, CA: 2001. TR-112350-V4.

State of the Art:

American Society of Civil Engineers (ASCE), Civil Works for Hydroelectric Facilities –

Guidelines for Life Extension and Upgrade, ASCE Hydropower Task Committee, 2007.

Bureau of Reclamation, Canal Lining Demonstration Project – Year 10 Final Report, R-02-

03, November 2002.


Rev. 1.0, 12/08/2011 56

Tennessee Valley Authority (TVA), Ocoee Flume Resumes Operation, TVA News Release,

April 22, 2011.

Standards:

Electric Power Research Institute (EPRI), Increased Efficiency of Hydroelectric Power, EM-

2407, Research Project 1745-1, Final Report, June 1982.

United States Army Corps of Engineers (USACE), Engineering and Design – Hydraulic Design

of Flood Control Channels, EM 1110-2-1601, June 1994.

Zipparro, Vincent J. and Hans Hasen, Davis’ Handbook of Applied Hydraulics, 4th

Edition, 1993.


Draft Tube Gates

Revision 1.0, 12/08/2011

HAP – Best Practice Catalog – Draft Tube Gates

Rev. 1.0, 12/08/2011 58

1.0 Scope and Purpose .................................................................................................................. 59

1.1 Hydropower Taxonomy Position ........................................................................................ 59

1.1.1 Components ............................................................................................................. 59

1.2 Summary of Best Practices ................................................................................................. 60

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ....................... 60

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ..................... 60

1.3 Best Practice Cross-References .......................................................................................... 60

2.0 Technology Design Summary ................................................................................................. 61

2.1 Material and Design Technology Evolution ....................................................................... 61

2.2 State of the Art Technology ................................................................................................ 62

3.0 Operation and Maintenance Practices ..................................................................................... 63

3.1 Condition Assessment......................................................................................................... 63

3.2 Operations ........................................................................................................................... 64

3.3 Maintenance ........................................................................................................................ 65

4.0 Metrics, Monitoring and Analysis .......................................................................................... 66

4.1 Measures of Performance, Condition, and Reliability ........................................................ 66

4.2 Data Analysis ...................................................................................................................... 66

4.3 Integrated Improvements .................................................................................................... 66

5.0 Information Sources: ............................................................................................................... 67


Rev. 1.0, 12/08/2011 59


This best practice for draft tube gates addresses the technology, condition assessment,

operations, and maintenance best practices for the gates and associated operating equipment with

the objective to maximize performance and reliability of plant generating system.

The primary purpose of the draft tube gate is to protect the interior equipment of the hydropower

plant including the turbine by providing a barrier and blocking water flow during maintenance

and dewatering activities. Most draft tube gates fall under the category of “bulkhead gates or

stop logs” that are normally lifted vertically into place and installed under no flow conditions for

maintenance or emergency use. They typically spend a vast majority of their lifecycle in storage

rather than service. The gates may be sectioned or un-sectioned with the sectioned

subassemblies lifted into place individually and stacked vertically. Although different materials

have been used historically, draft tube gates are primarily made from carbon steel and therefore

will be the primary focus for this best practice.


Hydropower Facility → Water Conveyances → Draft Tube Gates

1.1.1 Components

The components of the draft tube gate system are those features that directly or indirectly

contribute to the effectiveness of the maintenance and dewatering operations. The

system is made up of the draft tube gates itself along with the gate operating equipment.

Draft Tube Gate: Also referred to as stop logs or bulkhead gates, these assemblies are

used to block water so that construction, maintenance, or repair work can be

accomplished in a dry environment. These gates are stored in a secure storage yard,

positioned by a crane, and dropped into slots on the pier, which is sometimes integrated

with the dam, to form a wall against the water.

Draft Tube Gate Seals: Gate seals function to close off the open gap between the edge of

a movable structure and a fixed sealing surface so as to prevent any water from passing

through the interface. The seals are typically rubber material, and formed from a flat

strip of rubber, or shaped by a molding or extrusion process.

Draft Tube Gate Hoists: Hoists are mechanical (electrically or manually driven),

hydraulic (oil or water), or pneumatically operated machines used to raise and lower in

place heavy water control features such as gates and stop logs. A lifting beam is

commonly a key component of the hoist system for draft tube gates.

Draft Tube Gate Bearing Structure: Openings are formed in reinforced concrete walls

with dedicated piers at the edge of the openings to hold the draft tube gates in place.

Slots are configured in the concrete piers to match the size and geometry at the edges of

the gate to allow for a tight fit.


Rev. 1.0, 12/08/2011 60



Monitor leakage and functionality of the draft tube gates and include findings in

the plant’s unit performance records. The plant should rountinely monitor and

maintain a record of unit performance at the Current Performance Level (CPL).



Routinely inspect draft tube gates, seals, hoists, and bearing structure

components for degradation.

Trend draft tube gates, seals, hoists and bearing structure components for

degradation and adjust life expectancy accordingly to ensure that the system has

the appropriate degree of functional reliability.

Routinely inspect and maintain draft tube gate operating hoist and lift

equipment.

Maintain documentation of installed performance level (IPL) and update when

modification to equipment is made (e.g. gate seal replacement/repair, concrete

piers/slots upgrade).

Include industry knowledge for modern draft tube gate system components and

maintenance practices to plant engineering standards.

1.3 Best Practice Cross-References

Civil – Penstocks, Tunnels, and Surge Tanks

Civil – Leakage and Releases

Civil – Trash Racks and Intakes

Civil – Flumes/Open Channels


Rev. 1.0, 12/08/2011 61



Figure 1: Norris Dam – Anderson/Campbell County, TN

A wide variety of draft tube gate designs have been used at hydropower plants over the

course of the last century. Popular designs implemented include slide gates, roller gates, and

stoplogs (wood or steel). As mentioned previously, the most commonly used gate is

constructed of carbon steel members and plate. These steel gates have the advantage of

being relatively inexpensive to construct and can be positioned using standard equipment.

The Norris hydro plant had been in operation for nearly 60 years without dewatering

equipment for the draft tubes. But modernization of the plant could not be accomplished

without dewatering. Shown in Figure 1 is the initial installation of one of the new draft tube

gates supported by the overhead traveling gantry crane connected by the lifting beam. The

overhead gantry and crane rail girder is shown in Figure 2 while undergoing load

testing. Other system components included in the design but not shown are the dewatering

pumps, draft tube gate guides, and seal bearing plates.


Rev. 1.0, 12/08/2011 62

Figure 2: Norris Dam – Anderson/Campbell County, TN

Difficulties have been experienced while lifting the draft tube gate without a lifting

beam. The design above includes the lifting beam, new crane hook, hook lift points on the

gate and gate dogging device for supporting the gate when not being utilized.


The primary technological advances for draft tube gates are in the areas of the seals and

corrosion protection of the steel. Seal geometry and means of attachment to the gate can be

selected so that the seal is not susceptible to being rolled over due to the velocity of the water

past the seal, or due to wedging of debris between the seal and the sealing surface. The

double stem top seal, shown in Figure 3, is highly desirable whether located on the top or

sides of the gate since it has the ability to equalize the pressure behind the seal. Concrete and

steel surfaces must be smooth, burr and rust free to prevent wear and damage to the seals.

For steel sealing surfaces, a stainless steel overlay or cladding can be utilized to provide the

seal with a rust free sliding surface. An important advancement in draft tube gate design and

fabrication in the past 40 years has been the use of rubber gate seals with a J-bulb or music

note shape (See Figure 4). This advanced seal design allows for movement by using

adjustable mounting attachments.

Figure 3: Solid Double Stem Seal Figure 4: Solid J-Bulb Seal


Rev. 1.0, 12/08/2011 63



Conditions and problems associated with a draft tube gate, its guides, rails and seal plates,

and crane can only be properly assessed if the various components are readily accessible.

The draft tube gate assemblies spend most of their life cycle in storage rather than in service.

The following are the primary attributes to be concerned with during a condition assessment

of the draft tube gate assembly:

Anomalies in gate slots in concrete piers

Condition of seals, crane and lifting components, and electrical parts

Debris jamming gates

Corroded, bent, and damaged structural gate members and gate components

These common problem areas for draft tube gates can be assessed by a series of routine

inspections to determine structural integrity, life expectancy, and necessary improvements.

Prior to an assessment all maintenance records, past inspection reports, and design drawings

should be collected and reviewed. Each component should have a known physical condition

and age from these supporting documents. This should assist in identifying existing problem

areas as well as previous repairs.

These assessments will primarily be performed by visual examination and physical

measurements using a combination of divers and Remote Operated Video (ROV) equipment

where necessary. The determining factors of which inspection method to utilize will depend

greatly on the plant specific dewatering capabilities and required data collection. When a

visual inspection is all that is required an ROV will typically be the most practical option.

For this the ROV should be equipped with a lighting system and high quality video with an

engineer present to direct the underwater observations and note areas of concern for either

immediate closer viewing or for future inspection using a diver [3]. A disadvantage of the

use of an ROV may be its limitation in turbid water due to poor visibility [4]. Diver

disadvantages include regulations that restrict the allowable depths and durations of dives,

the number of repeat dives in a given period, and limitations in cold climates [5]. Other

difficulties encountered when using divers is the plant must shutdown the unit being

inspected as well as the adjacent units.

The alkali chemical reactions caused by the chemistry between the water and concrete often

results in concrete expansion. This occurrence is commonly known as Alkali-Aggregate

Reaction (AAR). This will commonly cause the gate to bind due to the reduction of gate

opening and misalignment of the original opening with the gate geometry. Another cause of

gate slot irregularities are local deterioration and spalling of the concrete that can lead to the

pier slots geometry being out of tolerance with the gate. Exact measurements using

calibrated instruments are an essential part of evaluating the concrete slots during the visual

inspection. Therefore, gate slots and concrete piers that form the openings require access by

divers to perform a thorough condition assessment. When using a diver, this person should

be equipped with lighting, voice communication, and a video camera. Communication


Rev. 1.0, 12/08/2011 64

should be arranged so that the engineer supervising the inspection can view and be in direct

contact with the diver. This ensures all required measurements and information are obtained.

Seals become damaged mainly due to excessive wear and environmentally caused

deterioration (debris/flow past the seal). The visual inspection should carefully check for any

debris trapped between the seal and the sealing surface. Seals can also be damaged by

rolling over during gate lifting. The condition of the seal should be carefully documented,

being sure to note any cracks, chips, or disfigurement.

The crane condition assessment is meant to include the crane and all of the associated

components. A mobile gantry crane typically utilizes a lifting beam to raise and lower the

sectioned or un-sectioned draft tube gates into the gate slots. Common problems associated

with the lifting beam include floating debris blocking the gate’s lift lugs and malfunction of

the lifting beam sheaves or lift lug engagement device. If applicable, ensure moving parts

are properly lubricated, gearbox oil is free of contaminants/moisture, gears and bearings do

not have excessive wear, and hoist ropes have no broken strands or deformation. When

examining the rope it is important to evaluate the entire length especially the underside that

contacts the drum or sheaves. Typically visual inspection of the rope is sufficient, however if

the integrity or serviceability is in question for a critical application a non-destructive test

method called magnetic flux leakage (MFL) is available. This MFL testing may be

performed for further evaluation or the rope simply be replaced based on the associated cost

and feasibility. The gearbox inspection should ensure full operation cycle and desired speeds

are achieved. Abnormal sounds and vibrations coming from the gearbox may be indications

of internal problems. If abnormal sounds or vibrations are observed, further internal

inspection should be performed. [2]

Bent and damaged gate members could cause twisting of the gate, resulting in the gate not

being lifted smoothly. The assessment should carefully visually inspect for warped flanges

of wide-flange and channel steel members, misaligned or partially loose exterior plates, loose

bolts or rivets, other localized defects such as weld cracks and gouges, and signs of structural

overstress (i.e., excessive deflections). Note the functionality of all gate components such as

wheels and rollers and assess the condition of any coating that is present.

The carbon steel used for construction of these gates will frequently corrode due to the

aggressive environment experienced during storage or submerged conditions. This corrosion

can range from minor surface rust to significant section loss. The minor surface rust can

cause an abrasive and uneven sealing surface leading to degradation of the seals and leakage.

3.2 Operations

The draft tube gate functions during plant maintenance and dewatering activities, and is

typically stored in a site yard during plant operations. Therefore, draft tube gates are not

subjected to operational conditions. Problems associated with their functionality during these

maintenance and dewatering periods will be discussed in detail in the following section on

Maintenance.


Rev. 1.0, 12/08/2011 65

3.3 Maintenance

Opportunities to improve draft tube gate performance involves properly diagnosing any of

the common problems noted above in the Condition Assessment section, determining the

apparent or root cause, and applying the most appropriate cost effective repair. It is

imperative that the required maintenance be performed on the gates and the associated

equipment. Performing the recommended maintenance will extend the life of the component

and will help avoid high costs encountered due to emergency repairs and lost revenue during

extended outages.

Problems with concrete openings not allowing the gates to be inserted properly are often due

to the expansive nature of the concrete and long term wear that reduces the clear opening

leading to gate binding. There are a few methods for alleviating this condition including

cutting back or trimming the concrete slots so as to enlarge the opening, trimming the edges

of the gates to restore proper clearance, and fabricating a new gate that allows for some

adjustments of its width. If concrete spalling is causing sealing difficulties because of

significant surface roughness and pitting, an epoxy concrete or cementitious repair mortar

may be used to restore the damaged surface.

Inadequate maintenance of seals and hoisting mechanisms can lead to several problems such

as seal damage/rolling, unequal hoisting chain length and loading, and motor overload.

When a gate is being lifted, seals can roll over and wedge the gate between the sealing

surfaces, thereby damaging the seal and increasing the lifting loads to be overcome by the

hoist. The corrective action involves replacing the gate seals and redesigning the means used

to attach the seal to the gate, or using reconfigured seal geometry. Most seals at today‘s

hydropower plants are made of rubber and can become worn or damaged over extended time

periods of use. Worn or damaged seals can cause excessive leakage which results not only in

loss of water, but can also lead to erosion of the concrete surfaces. Replacing the seals with

the current bulb type, which are adjustable, provides more allowance for movement in the

seal and provides capability to resist water pressures from either side. Bulb seals work best

when allowed to deflect rather than compressing the bulb against the sealing surface.

Motor overload results from a non-uniform torque transfer into the hoist’s gearbox.

Overload causes include motor undersizing, additional frictional or resisting gate loads, drive

shaft misalignment, old age and deterioration of the motor windings. Solutions include

replacing the motor, diagnosing the workings of the hoist machinery and replacing any

defective parts such as drive shafts, reduction gears, bearings and drive train. If the problem

cannot be shown to be directly related to the condition of the hoist, assess the gate to

determine the cause of the additional loads that the hoist must lift.

Other issues to look for at regular maintenance periods include debris that is jamming gates

and deformed/damaged gate structural members. Debris can readily get stuck between the

gate and support piers or guides, causing binding of the gate. A common solution is to

modify the gate to prevent debris from becoming wedged between the gate and gate supports.

Modifications may include extending plates from the upstream side of the gate to reduce the

width of the gap between the gate and the support piers or guides.


Rev. 1.0, 12/08/2011 66

Regarding the expected lifespan of the steel parts (plates, structural shapes, bolts, welds, etc.)

used for the draft tube gate assembly, 75 years is a reasonable service life when the proper

attention is given to the initial surface coating/protection and regularly scheduled

preventative maintenance. Often after 75 years of service, the area of the gate most in need

of major repair or replacement is around the perimeter of the gate adjacent to the gate seals.

Due to the gate seals being often inaccessible, this area is routinely not subjected to

inspection or preventative maintenance activities.

Bent and damaged gate structural members (i.e., steel wide flange and channel shapes) can

lead to warping of the gate, resulting in the gate not being lifted smoothly. The only viable

solution is to inspect the gate regularly, and remove and replace the damaged members as

necessary. If welds between steel members and plates look visually flawed ultrasonic testing

can be performed to determine if the weld needs to be reconstructed.

The damage caused by minor corrosion can be limited with minor preventative maintenance

such as coatings and the use of stainless steel overlays and cladding, as described in the State

of the Art Technology section of this report. If significant section loss is present due to

corrosion, complete or partial replacement may be justified for gate members and its

associated components.



For draft tube gates the measure for performance will be a direct result of its functionality.

The purpose of these gates is to protect and keep water away from the required portions of

the hydropower plant. It is important that these gates function properly not necessarily for

efficiency but for safety since failure can have dire consequences. Leakage of these gates

can be tolerated as long as safety and equipment protection are not compromised. The

leakage around the gate seals should be in the order of 0.01 gallons/minute per foot of wetted

perimeter for rubber seals. For metal on metal seals the allowable rate of leakage is 0.1

gallons/minute per foot of wetted perimeter. [1]

4.2 Data Analysis

Leakage of these gates can be tolerated as long as equipment protection and safety are not

compromised. Relatively small amounts of leakage can be tolerated and handled by pumping

water out of areas maintenance will be performed. However, if pumping becomes excessive

the cost of new seals or other corrective actions may be justified.


The field test results for leakage should be included when updating the plant’s unit

performance records. These records shall be made available to all involved personnel and

distributed accordingly for upcoming inspections.


Rev. 1.0, 12/08/2011 67


Baseline Knowledge:

American Society of Civil Engineers, Civil Works for Hydroelectric Facilities: Guidelines

for Life Extension and Upgrade, 2007.

US Army Corps of Engineers, Hydro Plant Risk Assessment Guide, Appendices E9 and E11,

September 2006.

HCI Publication Paper No. 072, Aging Plants – Time for a Physical: Conducting a

Comprehensive Condition Assessment and the Issues Identified, HydroVision 2008.

Bureau of Reclamation, McStraw, Bill, Inspection of Steel Penstocks and Pressure Conduits,

Facilities Instructions, Standards, and Techniques, Volume 2-8, September 1996.

US Army Corps of Engineers, Evaluation and Repair of Concrete Structures, Engineering

and Design, EM 1110-2-2002, 30 June 1995.

Hydro Life Extension Modernization Guides: Volume 1 – Overall Process, EPRI, Palo Alto,

CA: 1999. TR-112350-V1.


Leakage and Releases

Revision 1.0, 12/01/2011

HAP – Best Practice Catalog – Leakage and Releases

Rev. 1.0, 12/01/2011 69

1.0 Scope and Purpose…………………………………………………………………………………………………………….…..70


1.1.1 Causes of Leakage & Releases ........................................................................................... 70


1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ................................... 71

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ................................. 72


2.0 Technology Design Summary.………………………………………………………………………………………………72



3.0 Operation and Maintenance Practices.………………………………………………………………………………….73


3.2 Operations ...................................................................................................................... 74

3.3 Maintenance ................................................................................................................... 75

4.0 Metrics, Monitoring and Analysis……………….………………………………………..……………………………..76


4.2 Data Analysis ................................................................................................................. 76


5.0 Information Sources…………………………………………………………………………………………………..……….….76


Rev. 1.0, 12/01/2011 70


This best practice for leakage and releases addresses technology, condition assessment,


reliability. Leakage is an unintentional release of water and occurs to some extent at all

hydroelectric facilities. In most cases the loss from leakage is less than 1% of the average flow

[1]. There are certain cases where seepage can create a substantial loss of flow, but the cost

associated with preventing this loss is typically very high and almost always outweighs the cost

of lost generation. For these reasons, leakage is considered to have a minor impact on efficiency,

performance, and reliability of a hydro unit.

The release of excess water from spillways and sluiceways when flow exceeds storage and

generation capacity can become substantial over a long period of time. In some areas, meeting

minimum downstream flow requirements can also result in the release of substantial amounts of

water. Inadequate flow measurements can also lead to excess water losses through releases. A

variety of equipment is available on the market to generate electricity from releases without a

powerhouse structure [7]. This equipment has the potential to provide a sizeable amount of

power generation by harnessing the power from flow releases that previously generated no

revenue, contributing to unit efficiency, performance, and reliability.


This best practice encompasses the leakage and releases issues associated with spillways,

weirs, and sluiceways; also addresses the seepages through the abutments and foundation of

dams. The above chart indicates the position of this topic implied in the Taxonomy.

1.1.1 Causes of Leakage & Releases

Leakage is usually a minor problem in plant operations. In a survey on plant leakage, the

average loss from leakage reported by plant owners was less than 0.5% of the average

river flow. Very few plants reported leakage in excess of 1% [1].

The most common and controllable source of leakage occurs at spillway gates due to

inadequate sealing. ―Many old plants were built without gate seals for economic or other

reasons [1].‖ Even where gate seals are used, they deteriorate over time.

Another form of leakage comes from seepage. Seepage occurs under the foundation or

around the abutments of a dam. Small amounts of seepage are inevitable. Severe cases of


Rev. 1.0, 12/01/2011 71

seepage under the foundation, however, can cause major damage due to increased uplift

pressure and piping of soils in embankment dams [12]. These cases are safety concerns,

and repairs can be very costly. An example of this is Wolf Creek Dam in Kentucky where

seepage under the dam required hundreds of millions of dollars in repairs [2].

Seepage around abutments can divert a portion of the reservoir‘s flow around the dam.

―These leaks usually cannot be prevented except by redoing the upstream cut-off or grout

curtain of the dam and even then may not be possible to stop [1].‖ These techniques are

costly, but in certain cases where it is found that seepage can be prevented, the reduction

in losses can be substantial.

The primary purposes of releases are to maintain a minimum required flow downstream

of the dam and to regulate the water level of the reservoir. Minimum flow requirements

ensure that various needs of the downstream community are met, such as:

Protecting water quality and aquatic resources.

Ensuring year-round navigation.

Providing water for power production and municipal and industrial use

downstream [3].

Several examples of plants with flow release requirements are found in Flow

Measurement at Hydro Facilities: Achieving Efficiency, Compliance, and Optimal

Operation [4].

Generation and releases make up the flow that a plant produces downstream. Inaccurate

flow measurements from these sources can lead to an excess or insufficient flow being

released from the reservoir. In order to provide a flow that meets regional requirements,

many plants release more water than the required amount. Over time, this excess release

can become a substantial loss of generation revenue. To obtain the highest efficiency,

care should be taken to release the minimum amount of water above the generation

capacity to meet flow requirements. When releases are unavoidable, accurate flow

measurements and gate calibration can assist in providing increased efficiency.



Routine monitoring and recording of gate leakage and downstream seepage.

Trend gate leakage to trigger feasibility studies of seal replacement/addition or

gate replacement.

Trend downstream seepage to trigger feasibility studies of prevention techniques.

Obtain information of releases at Current Performance Level (CPL) by

measurements or models if none is currently available.


Rev. 1.0, 12/01/2011 72

Limit releases to minimum required flow, and only release when required.

Use information of releases at CPL to regulate releases.

Periodic comparison of the CPL of releases to the Potential Performance Level

(PPL) to trigger feasibility studies of major upgrades.


modifications are made (e.g. replacement/addition of seals, prevention of

seepage, addition of generating equipment, changes in release control).

Include industry acknowledged ―up to date‖ choices, for leakage prevention and

release control practices to plant engineering standards.


Monitor conveyance components and gates for signs of excessive leakage, and

repair or replace damaged or defective components causing the leakage.


Civil – Penstocks, Tunnels, & Surge Tanks

Civil – Trash Racks & Intakes



Gate seals are used to close the gap between the edge of a movable gate and a fixed sealing

surface. Most gates of modern hydroelectric plants have seals that are made of rubber.

However, wood, plastic, and even leather have been utilized for gates, typically under low

head applications. Dissimilar metal was also a common pre-1950‘s seal material and was

seen as a more durable, longer-lasting option [14].

Performance levels for leakage and releases can be stated at three levels as follows:

The Installed Performance Level (IPL) is described as the loss characteristics at the

time of the plant‘s commissioning or at the point when an upgrade, addition, or

modification is made.

The Current Performance Level (CPL) is described by an accurate set of loss

characteristics encompassing all sources of leakage and releases. It is important to

locate and accurately quantify all sources of leakage and releases for this performance

level.

The Potential Performance Level (PPL) is ideally considered as the condition where

no power generation loss occurs from leakage or releases. However, this ideal

condition is never completely obtainable. Therefore, the PPL can be considered as the


Rev. 1.0, 12/01/2011 73

condition where the minimum amount of losses can be obtained through upgrade to

the best designs and technologies.


Performance data on leakage and releases is only as reliable as the methods used to collect

the data. Emerging and state of the art technology continues to provide increasingly accurate

instrumentation and analysis software used to calculate hydraulic flow properties. These tools

can then be used to determine the difference between the CPL and the PPL of hydro plant

leakage and releases.

State of the art design of gate seals typically incorporates rubber as the primary seal material.

Although the designed service life of rubber seals does not greatly exceed that of other

materials, the biggest advantage comes from the reduction in leakage around the seals.

Leakage around rubber seals is approximately 10 times less than that of metal on metal seals

[14].



To inspect for leakage from gates, visual inspection can be performed by observing if any

water flows from the gates when they are closed. If the gates are not visible, it may be

possible to observe the flow from their outlets.

To inspect for leakage caused by abutment seepage, a variety of methods may be

implemented. In some cases simple visual inspection can be used. Muddy tailwater flows,

sinkholes, and downstream appearances of leakage are all possible signs of seepage. Figure 1

on the following page shows an example of the appearance of leakage from Center Hill Dam

in Tennessee [5]. Other cases may require the use of electronic, audio, or magnetic field

measuring devices to find the cause of seepage [8] [9]. Seepage Analysis and Control for

Dams provides guidance in seepage analysis [12].


Rev. 1.0, 12/01/2011 74

Figure 1: Appearance of Leakage (Center Hill Dam) [7]

It has historically been difficult to accurately measure the flows released from gates and

spillways. Antiquated plants have often relied only on charts that estimate flows for given

gate opening heights. In plants where accurate measurements of flow release are unavailable,

tests may be run to obtain flow data and/or a physical or computer model can be produced.

Using data collected through these methods, accurate flow measurements can be obtained. A

list of flow tests along with their applicability and advantages can be found in Flow

Measurements at Hydro Facilities: Achieving Efficiency, Compliance, and Optimal

Operation [4].

3.2 Operations

Gate seals deteriorate over time and they should be inspected periodically. Any leaks

discovered should be recorded and their severity monitored. While a small leak may cause a

negligible loss, if left unchecked, it can become a much larger loss over time.

Seepage in one form or another occurs at all dams. Therefore, the appearance of any of the

signs of seepage previously mentioned may not indicate a need for repair. These signs should

be monitored. If they worsen or are accompanied by other signs, the operators should

investigate the source of seepage before permanent damage occurs. Downstream appearances

of water should be monitored. These may be from a separate source or may be water

escaping the reservoir through seepage. The volume of flow from these sources should be

recorded regularly, and any increases may indicate a need for further investigation [12].

Once accurate flow measurements are obtained, they can be used to regulate releases more

efficiently. In plants where previous data of flow through gates and spillways are available,

the flow measurements can be used for gate calibration. In plants where no previous data of

flow through gates and spillways is available, the flow measurements can be used to

implement a procedure for flow control.


Rev. 1.0, 12/01/2011 75

Operators should consider altering generating schedules if excess amounts of water are being

released through spillways and gates. Any water released from the reservoir that is not used

to generate electricity is ultimately a loss of revenue.

3.3 Maintenance

Over time, gate seals will deteriorate and will need to be replaced. If possible, seals should be

replaced when the gates are out of use, either from dewatering or seasonal reservoir level

drops. To reduce maintenance, the use of improved seals may be a cost effective solution. In

cases where no seals are present, it may be cost effective to install seals on the gates. In

extreme cases of leakage, particularly where gates are severely deteriorated or have an

outdated design, it may be cost effective to replace the gate entirely if the addition or

replacement of seals is not sufficient.

Seepage prevention is typically a costly improvement and doesn‘t always fix the problem.

Grout curtains are the most common form of seepage prevention [13]. Even after they are

installed, seepage water may still find a path around the grouting or may find an outlet

further downstream. In the case of Great Falls Dam in Tennessee, an extensive grouting

program was successful in stopping 98% of reservoir leakage [6], but the largest of the

uncorrected leakage, located a few hundred feet downstream from the powerhouse, has

increased since the grout curtain was installed. This leakage can be seen in Figure 2.

Operators must take care to ensure that seepage prevention is a cost effective endeavor. In

many cases the small amount of water lost cannot justify the cost of correcting the problem.

A variety of seepage control methods and their appropriate applications can be found in

Seepage Analysis and Control for Dams, EM 1110-2-1901 [12].

At some point every plant must release water due to the generator or reservoir capacity limit.

Some plants, however, require a large volume of releases for environmental purposes. There

is a variety of equipment that can be installed to generate power from these types of releases

without the need for a powerhouse. Some of the most recent hydro generation equipment can

be found in ―Top 5 Developments in Hydro‖ [7]. Among these are a fully-sealed combined

axial turbine and generator [10] and hydrokinetic technologies [11]. These options can utilize

previously unused generation potential from environmental releases.

Figure 2: Great Falls Leakage (powerhouse shown at left)


Rev. 1.0, 12/01/2011 76

Additionally, some plants use releases to provide required dissolved oxygen concentrations

downstream of the dam. For these plants, the releases may not coincide with minimum flow

requirements and therefore contribute to decreased plant efficiency. Other means of

providing minimum dissolved oxygen, such as aeration weirs or aerating turbines, are

recommended in this case.



The fundamental process of a hydro plant can be described by the power equation. In the

case of leakage and releases, the power loss can be determined based of the following

calculation:

Where: · P is the power loss of the hydroelectric plant (MW)

· Q is the flow rate lost through leakage or releases (ft3/s)


· H is the effective pressure head across the system (ft)

The general expression for power loss (P):

4.2 Data Analysis

Analysis of performance data shall determine plant efficiency relative to power generation.

The results from the analysis (CPL) shall be compared to previous or original performance

data (IPL) as well as the efficiency gained from potential improvements to leakage and

releases (PPL). The cost of rehabilitation and internal rate of return must be calculated to

determine if improvements are justified.




Generation Control), but if not, hard copies of the data should be made available to all

involved personnel – particularly unit operators, their importance to be emphasized, and their

ability to be understood and confirmed. Justified projects a method to constantly monitor unit

performance should be implemented.

5.0 Information Sources

Baseline Knowledge:

Electric Power Research Institute (EPRI), Increased Efficiency of Hydroelectric Power, EM-

2407, June 1982


Rev. 1.0, 12/01/2011 77

United States Army Corps of Engineers (USACE), Wolf Creek Dam Seepage Rehabilitation

Project, Retrieved from http://www.lrn. usace.army.mil/wolfcreek/, Page last updated on

April 19, 2011

Tennessee Valley Authority (TVA), Managing River System Flows, Retrieved from

http://www.tva.gov/river/lakeinfo/systemwide.htm

EPRI, Hydropower Technology Roundup Report: Flow Measurement at Hydro Facilities:

Achieving Efficiency, Compliance, and Optimal Operation, TR-113584-V5, January 2002

USACE, Seepage, Retrieved from http://www.lrn.usace.army.mil/centerhill/pdf/ seepage.pdf

TVA, Great Falls Hydro Plant - Dam Safety Instrumentation Project Performance Report,

EDMS J22060427001, 2005

Hydro Life Extension Modernization Guides: Volume 1 – Overall Processes, EPRI, Palo

Alto, CA: 1999. TR-112350-V1.

State of the Art

Top 5 Developments in Hydro, International Water Power and Dam Construction, January

26, 2011

Diagnosing Dam Seepage, International Water Power and Dam Construction, March 21,

2011

Montgomery, J. R., M. L. Jessop, M. J. Wallace, and V. O. Kofoed, Using Controlled Source

Audio Frequency Domain Magnetics for Seepage Diagnosis of Earthen Embankments,

SAGEEP 22, 785, March 2009

Opsahl, E., and Ø. Krøvel, Installing the Turbinator, International Water Power and Dam

Construction, December 22, 2010

Hydro Green Energy, LLC, Full Operations Initiated at Nation’s First Commercial

Hydrokinetic Power Station, Retrieved from http://www.hgenergy.com/ moellerrelease.pdf

Standards:

USACE, Seepage Analysis and Control for Dams, EM 1110-2-1901, April 30, 1993

USACE, Engineering and Design - Planning and Design of Navigation Dams, EM 1110-2-

2607, July 31, 1995

American Society of Civil Engineers, Civil Works for Hydroelectric Facilities: Guidelines

for Life Extension and Upgrade, 2007


Francis Turbine

Revision 1.0, 12/06/2011

HAP – Best Practice Catalog – Francis Turbine

Rev. 1.0, 12/06/2011 79

1.0 Scope and Purpose ............................................................................................................. 80


1.1.1 Francis Turbine Components .................................................................................. 80


1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ....................... 82

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ..................... 83


2.0 Technology Design Summary ............................................................................................ 84



3.0 Operation and Maintenance Practices ................................................................................ 86


3.2 Operations ...................................................................................................................... 92

3.3 Maintenance ................................................................................................................... 92

4.0 Metrics, Monitoring and Analysis ..................................................................................... 97


4.2 Data Analysis ................................................................................................................. 98


5.0 Information Sources: .......................................................................................................... 99


Rev. 1.0, 12/06/2011 80


This best practice for a Francis turbine addresses its technology, condition assessment,

operations, and maintenance best practices with the objective to maximize its performance and

reliability. The primary purpose of the turbine is to function as the prime mover providing direct

horsepower to the generator. It is the most significant system in a hydro unit. How the turbine is

designed, operated, and maintained provides the most impact to the efficiency, performance, and

reliability of a hydro unit.


Hydropower Facility → Powerhouse → Power Train Equipment → Turbine → Francis

Turbine

1.1.1 Francis Turbine Components

Performance and reliability related components of a Francis turbine consist of a spiral

case, stay ring/stay vanes, wicket gates, vacuum breaker, reaction type runner, aeration

device, and draft tube.

Spiral Case: The function of the spiral case (or scroll case) is to supply water from the

penstock to the stay vanes and through its unique shape of continual cross sectional area

reduction, maintain a near uniform velocity of water around the stay vanes and wicket

gates.

Stay Ring/Vanes: The function of the stay vanes (and stay ring) is to align the flow of

water from the spiral casing to the wicket gates. They also usually function as support

columns in vertical units for supporting the static weight of the unit‘s stationary

components and hydraulic thrust during turbine operation.

Wicket Gates: The function of the wicket gates is primarily to control the quantity of

water entering the turbine runner, thereby controlling power output. Secondarily, the

gates control the angle of the high tangential velocity water striking the runner bucket

surface. The optimum angle of attack will be at peak efficiency. The wicket gates also

function as a closure valve to minimize leakage through the turbine while it is shut down.

Leakage can also originate from water passing by the end seals on the gates between the

top end of the gates and the head cover, and the bottom end of the gates and the bottom

ring.

Runner: The function of the runner is to convert the potential energy of pressure (head)

and flow of water into mechanical energy or rotational horsepower which is supplied

directly to the turbine shaft. There are various types, from horizontal to vertical

orientation, single discharge, double discharge, and overhung designs. The most

prevalent type is a vertical unit.

Vacuum Breaker: The function of the vacuum breaker is to admit air to a zone near the

turbine runner [2]. It is usually an automatic device either spring loaded or cam operated

off the wicket gate shifting ring. For reaction turbines it is used for drawing in

atmospheric air at low gate openings, such as synchronizing and speed no load, to reduce


Rev. 1.0, 12/06/2011 81

vibration and rough operation. While this reduces rough operation, it also reduces turbine

efficiency by introducing vacuum and air vortex beneath the runner.

Aeration Device: The function of an aeration device is for inlet of air into the turbine to

provide for an increase in dissolved oxygen in the tailrace waterway for environmental

enhancements. The device can be either active or passive in design with the passive

designs being more common. An active design would include some type of motorized

blower or compressor to force air into the turbine for mixing with water in the turbine

and/or draft tube. A passive design would consist of some type of addition or

modification to a turbine runner to naturally draw in atmospheric air into the turbine.

This in its most basic form is done through adding baffles to vacuum breaker air

discharge ports in the crown or nose cone of the turbine runner and blocking the vacuum

breaker open. The latest and most efficient method is by an aerating turbine runner

designed and built to discharge the air through internal porting in the runner and out the

blade tips.

Draft Tube: The function of the draft tube is to gradually slow down the high discharge

velocity water capturing the kinetic energy from the water, which is usually below

atmospheric pressure. In most cases, it has an elbow in order to minimize excavation for

the unit. The head recovery from the draft tube is the difference between the velocity

head at the runner discharge and draft tube discharge overall, increasing the head across

the turbine. The larger the head differential is across the turbine, the higher the turbine

power output. The draft tube should be steel lined from the discharge ring to the point

where the water velocity reduces to about 20 ft/s, which is considered below concrete

scouring velocity [1].

Non-performance but reliability related components of a Francis turbine include the

wicket gate mechanism / servomotors, head cover, bottom ring, turbine shaft, guide

bearing, and mechanical seals / packing.

Wicket Gate Mechanism / Servomotors: The function of the wicket gate mechanism and

servomotors is to control the opening and closing of the wicket gate assembly. The

mechanism includes arms, linkages, pins, shear pins, turnbuckles or eccentric pins for

closure adjustment, operating ring (or shift ring, and bearing pads), and bushings either

greased bronze or greaseless type. Servomotors are usually hydraulically actuated using

high pressure oil from the unit governor. In some limited cases a very small unit may

have electro-mechanical servomotors.

Head Cover: The head cover is a pressurized structural member covering the turbine

runner chamber that functions as a water barrier to seal the turbine. It also serves as a

carrier for the upper wicket gate bushings, upper seal surface for the wicket gate vanes,

support for the gate operating ring, carrier for the runner stationary seal rings, and support

for the turbine guide bearing.

Bottom Ring: The bottom ring serves as a carrier for the bottom wicket gate bushings,

bottom seal surface for the wicket gate vanes, and a carrier for the bottom runner

stationary seal ring.


Rev. 1.0, 12/06/2011 82

Turbine Shaft: The function of the turbine shaft is to transfer the torque from the turbine

runner to the generator shaft and generator rotor. The shaft typically has a bearing journal

for oil lubricated hydrodynamic guide bearings on the turbine runner end or wearing

sleeve for water lubricated guide bearings. Shafts are usually manufactured from forged

steel, but some of the largest shafts can be fabricated.

Guide Bearing: The function of the turbine guide bearing is to resist the mechanical

imbalance and hydraulic side loads from the turbine runner thereby maintaining the

turbine runner in its centered position in the runner seals. It is typically mounted as close

as practical to the turbine runner and supported by the head cover. Turbine guide

bearings are usually either oil lubricated hydrodynamic (babbitted) bearings or water

lubricated (plastic, wood, or composite) bearings.

Mechanical Seals / Packing: Sealing components in the turbine includes the seal for the

turbine shaft and the wicket gate stem seals. Shaft seals are typically either packing

boxes with square braided packing or for high speed units a mechanical seal is required.

Wicket gate stem packing is usually either a square braided compression packing, a V

type or Chevron packing, or some type of hydraulic elastomer seal. Although in the

truest sense any sealing components on a turbine could be a performance issue, since any

leakage that by-passes the turbine runner is a loss of energy, the leakage into the wheel

pit is considered insignificant to the overall flow through the turbine.



Periodic testing to establish accurate current unit performance characteristics

and limits.

Dissemination of accurate unit performance characteristics to unit operators,

local and remote control and decision support systems, and other personnel and

offices that influence unit dispatch or generation performance.

Real-time monitoring and periodic analysis of unit performance at Current

Performance Level (CPL) to detect and mitigate deviations from expected

efficiency for the Installed Performance Level (IPL) due to degradation or

instrument malfunction.

Periodic comparison of the CPL to the Potential Performance Level (PPL) to

trigger feasibility studies of major upgrades.


made (e.g., hydraulic profiling, draft tube slot fillers, unit upgrade).

Trend loss of turbine performance due to condition degradation for such causes

as metal loss (cavitation, erosion, and corrosion), opening of runner seal,

opening of wicket gate clearances, and increasing water passage surface


Rev. 1.0, 12/06/2011 83

roughness. Adjust maintenance and capitalization programs to correct

deficiencies.

Include industry acknowledged ―up to date‖ choices for turbine components

materials and maintenance practices.


Use ASTM A487 / A743 CA6NM stainless steel to manufacture Francis turbine

runners, wicket gates, and water lubricated bearing shaft sleeves to maximize

resistance to erosion, abrasive wear, and cavitation. [18, 19]

Bushing clearances greater than two times the design are considered excessive

and warrants replacement.

Wicket gate shear pins (mechanical fuse) are an engineered product designed to

prevent failures of more costly components in the mechanism. When replacing

pins or spares pins, it is best practice, to purchase the pin material from one

manufacturer to ensure material properties remain consistent. Prototype sample

pins are manufactured and tested to finalize the diameter for the final pin shop

drawing.

Turbine shaft areas near the shaft seal that are exposed to water should be sealed

with a robust coating such as an epoxy paint to prevent corrosion of the shaft.

Damage from erosion and cavitation on component wetted surfaces are repaired

using 309L stainless steel welding electrodes. The electrodes increase damage

resistance.

When turbine runner seal clearances reach twice the design value one should

consider rehabilitating or replacing the runner due to efficiency loss.

Francis turbines with heads above 100 feet should be considered as candidates

for embedded wicket gate vane end seals and wicket gates fabricated from

stainless steel to mitigate leakage and wear.

Adequate coating of the turbine wetted components not only prevents corrosion

but has added benefits of improved performance.

Vacuum breakers should be inspected routinely and adjusted for optimal

performance.

Discharge areas on a turbine runner for aeration devices should be clad with

stainless steel to mitigate cavitation.

Wicket gate mechanism linkage bushings should be of the greaseless type to

reduce grease discharge to the wheel pit and ultimately the station sump. Using

greaseless bushings in other applications possible; however, care must be taken


Rev. 1.0, 12/06/2011 84

in any retrofit to ensure that the servomotors are strong enough to operate even

after a 25% increase in long term friction.

For applications above 200 feet of head, stainless steel wearing plates embedded

into the head cover and bottom ring immediately above and below the wicket

gate vanes are recommended.

Kidney loop filtration should be installed on turbine guide bearing oil systems.

Automatic strainers with internal backwash should be installed to supply

uninterrupted supply of clean water to water lubricated turbine guide bearings.

Monitor trends of decrease in condition of turbine (decrease in Condition

Indicator (CI)) and decrease in reliability (an increase in Equivalent Forced

Outage Rate (EFOR), a decrease in Effective Availability Factor (EAF)).

Adjust maintenance and capitalization programs to correct deficiencies.


I&C - Automation Best Practice

Mechanical - Lubrication Best Practice

Mechanical - Generator Best Practice

Mechanical – Governor Best Practice

Mechanical – Raw Water Best Practice



Francis turbine runners are typically manufactured as one piece, typically either as a casting

or as a welded fabrication. Very old runners, from the early 1900‘s or before, could have

been cast from cast iron or bronze, later replaced with cast carbon steel; and today either cast

or fabricated from carbon steel or stainless steel. Just as materials have improved for modern

turbine runners, so has the design and manufacturing to provide enhanced performance for

power, efficiency, and reduced cavitation damage.

Best practice for the turbine begins with a superior design to maximize and establish the

baseline performance while minimizing damage due to various factors, including cavitation,

pitting, and rough operation. The advent of computerized design and manufacturing occurred

in the late 1970‘s through 1980‘s and made many of the advancements of today possible.

Modern Computational Fluid Dynamics (CFD) flow analysis, Finite Element Analysis

techniques (FEA) for engineering, and Computer Numerically Controlled (CNC) in

manufacturing have significantly improved turbine efficiency and production accuracy.

Performance levels for turbine designs can be stated at three levels as follows:


Rev. 1.0, 12/06/2011 85

The Installed Performance Level (IPL) is described by the unit performance

characteristics at the time of commissioning. These may be determined from reports

and records of efficiency and/or model testing conducted prior to and during unit

commissioning.

The Current Performance Level (CPL) is described by an accurate set of unit

performance characteristics determined by unit efficiency testing, which requires the

simultaneous measurement of flow, head, and power under a range of operating

conditions, as specified in the standards referenced in this document.

Determination of the Potential Performance Level (PPL) typically requires reference

to new turbine design information from manufacturer to establish the achievable unit

performance characteristics of replacement turbine(s).


Turbine efficiency is likely the most important factor in an assessment to determine

rehabilitation or replacement. Such testing may show CPL has degraded significantly from

IPL. Figure 1 is an example of the peak efficiency of a Francis unit with a percentage point

drop in peak efficiency of greater than 3 in a 35 year period since it went into commercial

operation. Regardless of whether performance has degraded or not, newer turbine designs

are usually more efficient than those designed 30 to 40 years ago. Also, a new turbine can be

designed using actual historical operations rather than original design data providing a

turbine more accurately suited for the site.

Figure 1: Example - Original vs. Degraded Performance Curves [8]

Newer state of the art turbine designs can not only achieve the PPL but also provide

decreased cavitation damage based on better hydraulic design and materials [3]. Figures 2

and 3 show an original runner and its state of the art stainless steel replacement runner, as a

comparison. Figure 6 shows a state of the art aerating runner which discharges the air from

the bucket tips.

56

60

64

68

72

76

80

84

88

92

4 6 8 10 12 14 16 18 20 22 24 26 28

Ove

rall

Effi

cie

ncy

(%

)

Generator Output (MW)

1950 Data

1985 Data

OperatingCharacteristics

Performance at 88-ft Gross Head


Rev. 1.0, 12/06/2011 86

Figure 2: Original Runner

Figure 3: New Stainless Steel Replacement Runner



After the commercial operation begins, how the turbine is operated and maintained will have

a huge impact on loss prevention of the IPL and CPL and maintaining reliability. Materials

for turbine runners are usually cast iron, steel, or stainless steel. As a best practice, the most

common material being used today for new state of the art runners is ASTM A487 / A743

CA6NM stainless steel [18, 19]. It is cavitation resistant, fairly easy to cast and fabricate,

and can usually be weld repaired without post heat treatment. The same is true for wicket

gate materials.

The other wetted turbine components such as stay vanes, spiral cases, and draft tubes are

usually constructed from steel due to strength requirements. Some components have

stainless steel cladding overlaid in critical areas. The most significant contributor to

performance loss for all wetted components is any metal loss due to cavitation, as shown in

Figure 4, abrasive erosion, surface finish degradation, and the poor quality of past repairs

which can distort the hydraulic design contours of components.

Condition assessment of those flow components must address any past damage, location of

damage, repeat damage, and resulting increase in surface roughness. Evaluating the overall

condition of a turbine and all its components may show that a new state of the art turbine

runner with enhanced power and efficiency may provide sufficient benefits to justify its

replacement, including rehabilitating related components, as compared to maintaining current

turbine with existing efficiency [3].


Rev. 1.0, 12/06/2011 87

Figure 4: Typical Cavitation Damage to Runner Blade

The vacuum breaker or air inlet valve is usually mounted directly to turbine head cover and

will probably require disassembly for a thorough condition assessment. A condition

assessment would include observing operation of the vacuum breaker during startup. Loose

operation or banging of the seals would indicate a misadjusted or worn device requiring

maintenance. Unit performance can also be checked with valve opened, closed, and in

normal operating position to measure and contrast any difference in unit performance that

would indicate a problem with the valve.

Aeration devices for the turbine can take the form of more complex active systems, such as

motorized blowers, to the less complex passive systems, such as baffles and self aspirating

runner designs. The passive designs are being the most common practices, as shown in

Figures 5 and 6.

Focusing on the most common designs, the condition assessment would include inspections

of the air discharge passages in the turbine and any observable cavitation or erosion damage

that might affect its normal operation. A decrease of normal dissolve oxygen uptake in the

waterway downstream could be an indicator of degradation of the condition of the aeration

device.


Rev. 1.0, 12/06/2011 88

Figure 5: Aeration Baffles on Nose Cone

Figure 6: Aerating Runner (through bucket tips)

The wicket gate mechanism (Figure 7) and the actuating servomotors provide for the

regulation and control of the turbine. The condition assessment of the components would

include measurements of wear or looseness in the arms, linkages, pins, shear pins,

turnbuckles (or eccentric pins), linkage bushings, operating ring (and bearing pads), and

wicket gate stem bushings. It is important to note, that excessive wear in the components is

additive and can result in losing off-line regulating control of the wicket gates making it

more difficult to synchronize the unit. This is an indicator that rehabilitation on the

components is necessary. Measurement of wear is difficult without disassembly, however,

extreme wear can be observed as loss of motion in gate movements.

In some turbine designs it is possible during un-watered outages, to measure the clearance

between the wicket gate stem journals and the inside diameter of the bushings with feeler

gauges. Abnormal water leakage around the wicket gates in the turbine wheel pit after an

attempt to adjust the stem packing is an indicator of excessive wicket gate stem bushing

wear. As a best practice, bushing to journal clearance greater than two times the design is

considered excessive. An increase in the number of shear pin failures over a given period is

an indication of either a problem with the design and material used to manufacture the pins or

a problem with binding in the mechanism.


Rev. 1.0, 12/06/2011 89

Figure 7: Wicket Gate Mechanism

Hydraulic servomotors (Figure 8) are usually very reliable, with the most common problem

being oil leakage from the seal on the actuating rod. The amount of acceptable leakage is

dependent on the seal design and site maintenance requirements. Hydraulic seals will leak

very little whereas a square braided compression packing will leak more. A condition

assessment would include observation of the leakage and discussion with the plant

maintenance technicians as to the amount of daily or weekly maintenance required.

Excessive maintenance would require the change of the seal or packing. It is important to

note and observe if the actuating rod is smooth, without any scoring or grooves which would

prevent sealing. If the rod is damaged it will require repair or replacement.

Figure 8: Wicket Gate Servomotor

The condition assessment of the head cover and bottom ring consists mainly of visually

inspecting the wetted surfaces for erosion and cavitation. Cracking in either component or

deep erosion in the water barrier of the head cover is a major concern and must be addressed

immediately. Excessive corrosion of the joint bolting (stay ring flange or split joints) or

failure of the bolting is a major concern and must be addressed immediately. The assessment

would also include observation of any galling between the ends of the wicket gate vanes, the

head cover, bottom ring and damage to embedded end seals.


Rev. 1.0, 12/06/2011 90

The condition assessment of the turbine shaft (Figure 9) would include observation of

corrosion and defects on the exposed surface. Any cracking as identified by the

Nondestructive Examination (NDE) methods is a major concern and must be addressed

immediately.

Bearing journals and sleeves must be smooth and free of defects (only accessible with

bearing removed) to ensure the reliability of the turbine guide bearing. As a best practice for

water lubrication turbine bearings, wearing sleeves are usually manufactured from ASTM

A487 / A743 CA6NM stainless steel either as a forging or centrifugally cast [18, 19]. Areas

near the shaft seal that are exposed to water should be sealed with a robust coating such as an

epoxy paint to prevent corrosion of the shaft.

Figure 9: Turbine Shaft / Wheel Pit

Turbine guide bearings are usually either oil lubricated hydrodynamic bearings (Figure 10) or

water lubricated bearings (Figure 11), with the latter being found only in low head slow

speed units. The condition assessment of the oil lubricated type includes vibration

measurements (i.e. shaft throw) and temperature of the bearing in operation. Abnormal

indications of those could be a sign of failure of the babbitted surface (wipe), un-bonding of

the babbitt from the bearing housing, or contamination of the oil. The condition assessment

of a water lubricated type centers mainly on vibration measurements and success of

subsequent bearing adjustments if the design permits. An indication of a loose wearing sleeve

on the shaft is excessive shaft throw (vibration) even after adjusting the bearing. Non-

adjustable water lubricated bearings, or bearings worn beyond adjustment will require the

wearing liner (either wood, plastic, or composite) to be replaced.


Rev. 1.0, 12/06/2011 91

Figure 10: Babbitted Oil Journal Bearing

Figure 11: Water Lubricated Bearing

The condition assessment of the wicket gate stem seals or shaft seals usually includes the

observation of excessive water leakage in the turbine wheel pit area which can be viewed

visually or estimated by sump pump operation (if available). Excessive leakage, even after

adjustments (if possible by design), is an indication that the seals or packing must be

replaced.


Rev. 1.0, 12/06/2011 92

3.2 Operations

Since Francis turbines have a very narrow operating range for peak efficiency (Figure 12), it

is extremely important for plant operations to have an accurate operating curve for the units.

The curves originate from the manufacturer‘s model test data and post installation

performance testing. The performance of the turbine can degrade over time, due to cavitation

and/or erosion damage and resulting weld repairs, etc. Therefore, to maximize unit

efficiency, periodic performance testing, either as absolute or relative testing must be carried

out to update operational performance curves. An example of relative testing would be index

testing (using Winter Kennedy taps).

Figure 12: Typical Francis Performance Curve

―Frequent index testing, especially before and after major maintenance activities on a turbine,

should be made to detect changes in turbine performance at an early stage and establish

controls [8].‖ Plants should, as ―best practice,‖ perform periodic performance testing (such as

index testing according to PTC 18 [13]) to assure the most accurate operating curves are

available to optimize plant output. Routinely, this should be done on a 10 year cycle as a

minimum.

3.3 Maintenance

It is commonly accepted that turbines normally suffer from a progressive deterioration in

performance over time (in default of restorative action) [4]. Usual causes include cavitation

damage, abrasive erosion wear, galvanic corrosion, impact damage from debris passing

through, and errors in welding repairs to original runner blade profile and surface finish.

Performance related maintenance techniques involve mainly those weld repairs to cavitation

damage, abrasive erosion damage, and galvanic corrosion on the turbine components such as

the runner, wicket gates, stay vane, spiral case and draft tube. The usual best practice is to

perform cladding with a 309L stainless steel welding electrode to provide some cavitation

resistance. In some cases, original blade contour templates are available at the plant to

facilitate returning the blade back to Original Equipment Manufacturer (OEM)

specifications. A good reference for turbine maintenance is the USBR‘s FIST Volume 2-5,

60

65

70

75

80

85

90

5 7 9 11 13 15 17 19 21

Ove

rall

Eff

icie

nc

y (

%)



Rev. 1.0, 12/06/2011 93

Turbine Repair [6] and Hydro Wheels: A Guide to Maintaining and Improving Hydro Units

by T. Spicher [13].

Francis turbine runners usually have replaceable seal rings or wear rings on the outside

diameter of the crown and band, or provision for adding such in the future. It is essential to

maintain adequate sealing to prevent excessive hydraulic thrust loads on the generator thrust

bearing (bearing carrying the unit‘s axial load, i.e., static weight plus hydraulic thrust) and

prevent excessive water leakage by-passing the runner.

The generator thrust bearing is designed to handle hydraulic loads from the seals worn to

twice the design value [1]. Therefore, as a best practice, when runner seal clearances reach

twice the design value one should consider rehabilitating or replacing the runner. Seal ring

clearances are usually measured with feeler gauges during routine maintenance and

documented for trending over time. For high head units, leakage by these seal rings may

affect the overall efficiency of the turbine by 1 to 3% [5].

Worn wicket gate end clearances can also contribute to a decline in unit performance since

leakage contributes to power generation loss, particularly by those units with a low service

factor (i.e., gates in closed position for a significant period of time). In a new unit, the

leakage through properly designed wicket gates may be markedly less than 1% of full gate

discharge, however, over years of operation this could be doubled due to eroded end

clearances, worn stem journal bushings, and improperly adjusted toe to heel closures [5]. As

a best practice, turbines with heads above 100 feet should be considered as candidates for

embedded wicket gate vane end seals and wicket gates fabricated from stainless steel to

mitigate leakage and wear.

Investigations by the US Army Corps of Engineers (USACE) show minor modifications to

the stay vane - wicket gate system could result in an operation efficiency increases of 0.5 to

0.7% for the units studied [10]. As shown in reference [10], the modification takes the form

of profile change on the stay vane leading and trailing edges modifying the wake relative to

the wicket gate. These changes have to be studied in a Computational Fluid Dynamics

(CFD) model and/or physical model. In addition, such modifications can reduce fish injury

as one environmental benefit.

In some cases, Von Karman vortices can trail off the wicket gates during high flow

operation, impinging on the runner band and blades with resulting cavitation damage. Flow

profile modifications, including a narrowing of the lower trailing edges (as shown in Figure

13) of the wicket gates, can reduce the formation of vortices, and thus allow higher flow rates

and power output. The exact profile change should be designed based on CFD and/or

physical modeling.


Rev. 1.0, 12/06/2011 94

Figure 13: Wicket Gate Modification

Further studies by the USACE to improve turbine efficiency have found some relationship

between surface roughness of the turbine components, and degradation of the unit

performance [9]. It is commonly known that surface roughness on flow surfaces robs a

moving fluid of energy; similar to what is found in piping systems. A higher relative

roughness will increase the friction loss usually expressed in the head.

Since the power generated by a turbine is directly related to head, logically, any loss in head

by frictional losses of the water flowing through the turbine will be a loss in performance.

Improvements in surface finish include grinding and coating (painting) the surfaces. In some

cases, the USACE tests found efficiency improvements of 0.1 to 0.8% comparing pre-coated

versus post-coating performance [9]. However, the level of uncertainty of field testing

measurement can range up to 1%, which makes it difficult to quantify results within testing

error. Common maintenance best practice of providing adequate coating of the turbine

components to prevent surface corrosion does have added benefits of improved performance,

however unquantifiable.

By design, a vacuum breaker introduces atmospheric air into the sub-atmospheric area below

the runner reducing the pressure across the runner, thereby reducing efficiency. The vacuum

breaker should be able to work at the smallest possible gate setting to avoid vibration and

rough operation, but not admit air at the higher operating gate settings. Best practice for the

vacuum breaker includes periodic maintenance (during routine inspections) to assure proper

operation and evaluation of the condition of the main seals to prevent leakage. It is important

that any stroke dampening devices built into the vacuum breaker be checked and adjusted

annually to avoid excessive cycling (banging) of the seal during operation. The vacuum

breaker, being a mechanical device subject to frictional wear, will require major maintenance

(overhauling) based on number of cycles of operation, but typically every 10 to 20 years.

Maintenance of any aeration device on the turbine includes periodic inspection (during

routine inspections) and testing of components to ensure the device is operating according to

design. Areas adjacent to the air discharge in the turbine must be monitored for damage due


Rev. 1.0, 12/06/2011 95

to erosion or cavitation. As a best practice, those areas if not stainless steel already should be

clad with stainless steel to mitigate damage.

Pressures in the draft tube increase as the water flows from the elbow to the exit. If the top

of the draft tube gate slots (close to the elbow) is submerged (under tail water), water can be

drawn down into the draft tube due to the lower pressure there, increasing the total flow in

the draft tube from that point to the exit, thereby increasing the head loss and reducing the

unit efficiency. The closer the gate slot is to the centerline of the unit, the greater the effect.

The use of slot fillers to plug the upper openings of the gate slots have been shown to remedy

this problem and in some cases, improve efficiency by as much as 1% is considered a best

practice.

The wicket gate mechanism consists of arms, linkages, pins, shear pins, turnbuckles (or

eccentric pins), linkage bushings, operating ring (and bearing pads), and wicket gate stem

bushings. For greased bushing designs it is essential that the greasing system is functioning

to original specification with metered grease flowing to all points. It is important to grease

the wicket gate stem bushings and observe if the grease is entering the bushing clearance and

visually discharging. If not, this will have to be repaired immediately.

Greaseless bushing designs require less routine maintenance than the greased designs;

however the most common maintenance issue is broken or loose anti-rotation devices on the

pins. The greaseless bushings will wear at a more rapid rate than the greased bushings,

requiring replacements more frequently, such as on a 10 to 20 year cycle in contrast to a 30

to 40 year cycle for greased bushings.

As a best practice, the bushings on the wicket gate linkages are usually the greaseless type in

order to reduce the amount of grease discharging into the wheel pit area and ultimately

flowing into the powerhouse sump. Bushing applications in other turbine areas, such as

wicket gate stem bushings, operating ring pads, and servomotors are usually chosen based on

the owner‘s preference when comparing bushing life and reliability versus the owner‘s desire

to minimize the use of grease lubrication. However, it is important that each greaseless

bushing is designed correctly for the application.

In some cases the friction in greaseless bushings increases over time due to trapped wear

debris and incursion of silt and debris from the water, as compared to the greased bushings

which are flushed by the movement of the grease. An increase in long term operating

friction in greaseless applications means the wicket gate servomotors must be over designed

(particularly in retrofits) with excess capacity of at least 25% in order to ensure reliable

operation [11].

Major maintenance of the wicket gate mechanism includes replacement of the pins, pads,

bushings, and true machining of wear surfaces. This will be required every 10 to 40 years

depending on the design and operating conditions. Shear pins (mechanical fuse) are an

engineered product designed to prevent failures of more costly components in the

mechanism. It is best practice to purchase the pin material from one manufacturer to ensure

material properties remain constant. Prototype sample pins are manufactured and then broken


Rev. 1.0, 12/06/2011 96

in a test stand to determine actual shear properties. This test data is used to finalize the shear

area diameter for the final pin shop drawing.

Routine maintenance of wicket gate servomotors is minimal and usually only requires

changing of the actuating rod seals or packing when leakage become excessive. Major

maintenance includes an overhaul of the servomotor, requiring disassembly, and replacement

of bushings, seals, and piston rings.

Head cover and bottom ring routine maintenance is usually to ensure that the protective

coating on the wetted surfaces is intact and any erosion or cavitation is repaired before it

progressively worsens. Any galling damage at or near the ends of the wicket gate vanes

must be removed by grinding to prevent further galling or damage to the wicket gate

vane end seals. For higher head units with heads above 200 feet and/or poor water

quality units it is best practice to embed stainless steel wearing plates in the head cover

and bottom ring immediately above and below the wicket gate vane ends to mitigate

erosion and cavitation damage.

It is also common to install wicket gate vane end seals (either elastomer or bronze) into

these areas to minimize leakage. Unfortunately, it is also best practice to manufacture

wicket gates from stainless steel. Since stainless steel in contact with stainless steel can

experience a high degree of galling, it is imperative that the design of wicket gate up

thrust device be robust to resist the axial movement of the gate and prevent these

surfaces from contacting. Wicket gate up thrust is generated either by the hydraulic

pressure of water under the bottom stem and/or grease application pressure. Major

maintenance of the head cover and bottom ring includes blasting and Nondestructive

Examination (NDE) for cracking inspection, recoating, replacing wear plates and runner

stationary seal rings, and replacing wicket gate bushings.

Routine turbine shaft maintenance consists of minimizing the corrosion of the shaft

surface with a light coat of oil in the non-water contact areas and periodic re-coating of

areas that come in contact with water with a robust paint such as epoxy. Major

maintenance includes refurbishment on bearing journals, replacement of wearing sleeve,

and re-truing coupling faces during a major unit overhaul.

Turbine guide bearings are usually either oil lubricated hydrodynamic bearings or water

lubricated bearings. Maintenance of an oil lubricated bearing and its reliability are

directly connected to the quality of the supplied oil used for lubrication and cooling.

Any contamination of the oil either with debris or water will increase the likelihood of a

bearing failure. A best practice is to install a kidney loop filtration system capable of

continuously removing debris and water from the bearing oil supply. Maintenance of a

water lubricated bearing and its reliability are also directly connected to the quality of

the supplied water used for lubrication and cooling. Although in this case, with the

viscosity of the water being so low, the water functions more as a coolant than as a

lubricant. A best practice is to install an automatic strainer with internal backwash for

uninterrupted supply of clean water to the bearing without need of routine maintenance

to change or clean the filters. An uninterrupted supply is essential since any loss of

water flow during turbine operation will quickly overheat the anti-friction contact


Rev. 1.0, 12/06/2011 97

surface of the internal liner (plastic, wood, or composite) of the bearing resulting in a

rapid failure.

Since water lubricated bearings inherently wear which results in an increase in shaft

vibration (shaft throw), periodic maintenance is required to adjust the bearing to tighten

the running clearance. Some poorly designed bearings are non-adjustable and require

the internal lining to be replaced to tighten clearance. Extreme shaft vibration (shaft

throw) can cause contact of the turbine runner‘s seal rings, resulting in wear and the

possible failure of the seal rings and extended unit outage. Major maintenance of either

bearing type requires the refurbishment of the bearings, such as re-babbitting of an oil

bearing or re-lining the water lubricated bearing. In addition, for water lubricated

bearing, the shaft wearing sleeve may have to be machined true or replaced.

Sealing components in the turbine include the wicket gate stem seals and the seal for the

turbine shaft. Routine maintenance will vary according to the type of seal and the

operating conditions. Generally the hydraulic type seals, such as PolyPak seals, on

wicket gate stems are maintenance free, however, like o-ring seals, once they leak there

are no adjustments and must be replaced. Adjustable seal designs, such as with packing,

can be tightened to reduce the leakage. Excessive leakage, even after adjustment, is an

indication that the seals or packing must be replaced.

Seals for the turbine shaft vary from simple packing in a packing box around the shaft to

higher speed applications with mechanical seals. It is important to note that a certain amount

of leakage is required in a turbine shaft seal for cooling the seal (or packing), therefore zero

leakage is not the objective. Routine maintenance includes replacement of the packing in the

packing box or replacement of the composite (sacrificial) wearing component in the

mechanical seal. Major maintenance of all the applications consists of the routine

maintenance replacements and additional replacement of any opposing hard face wear

elements such as wear sleeves for packing and hard face wear elements for the mechanical

seals.



The fundamental process for a hydro turbine is described by the efficiency equation, which is

defined as the ratio of the power delivered by the turbine to the power of the water passing

through the turbine.

Where: · η is the hydraulic efficiency of the turbine

· P is the mechanical power produced at the turbine shaft (MW)

· ρ is the density of water (1000 kg/m3)

· g is the acceleration due to gravity (9.81 m/s2)

· Q is the flow rate passing through the turbine (m3/s)

· H is the effective pressure head across the turbine (m)


Rev. 1.0, 12/06/2011 98

The general expression for this efficiency (η): [14]

Turbine performance parameters for Francis units are defined in ASME PTC-18 [13] and

IEC 60041 [14], and typically include the following: Generator Output, Turbine Discharge,

Headwater and Tailwater Elevations, Inlet Head, Discharge Head, Gate Position, and Water

Temperature.

Typical vibration measurements may include: shaft displacement (x and y) at turbine and

generator bearings, and headcover and thrust bridge displacements (z). Acoustic emission (on

the draft tube access door or liner) may be measured to track relative cavitation noise.

The condition of the Francis turbine can be monitored by the Condition Indicator (CI) as

defined according to HAP Condition Assessment Manual, ORNL, October 2011 [12].

Unit reliability characteristics, as judged by its availability for generation, can be monitored

by use of the North American Electric Reliability Corporation‘s (NERC) performance

indicators, such Equivalent Availability Factor (EAF) and Equivalent Forced Outage Factor

(EFOR). These are used universally by the power industry. Many utilities supply data to the

Generating Availability Data System (GADS) maintained by NERC. This database of

operating information is used for improving the performance of electric generating

equipment. It can be used to support equipment reliability and availability analysis and

decision-making by GADS data users.

4.2 Data Analysis

Analysis of test data is defined in ASME PTC-18 [15] and IEC 60041 [16]. Basically,

determine unit efficiency and available power output relative to turbine discharge, head, gate

opening position, and determine operating limits based on vibration and acoustic emission

measurements (CPL). Compare results to previous or original unit test data (IPL), and

determine efficiency, capacity, annual energy, and revenue loss. Compare results to new unit

design data (from turbine manufacturer), and determine potential efficiency, capacity, annual

energy, and revenue gain (PPL). For the latter, calculate the installation/rehabilitation cost

and internal rate of return to determine upgrade justification. Separately, determine the

justification of draft tube profile modification using turbine manufacturer‘s data.

Trend runner seal clearances (top and bottom) relative to OEM design values. If

rehabilitation is required (resulting in complete unit disassembly), consider the value of

installing new design unit.

Trend wicket gate end clearances (top and bottom), and toe to heel closures relative to OEM

design values. If rehabilitation is required (resulting in complete unit disassembly), consider

the value of installing new design unit. If the turbine does not already have wicket gate end

seals (either spring loaded bronze or elastomer), analytically determine the annual energy and

revenue gain associated with their use. Calculate the implementation cost and internal rate of

return.


Rev. 1.0, 12/06/2011 99

Monitor the operation of vacuum breaker based on routine maintenance program and through

performance testing. Consider rehabilitating the vacuum breaker if it is leaking.

Analytically or using field test data, determine the efficiency, annual energy, and revenue

gain associated with the use of draft tube gate slot fillers. Calculate the implementation cost

and internal rate of return.

The condition assessment of a Francis turbine is quantified through the CI as derived

according to HAP Condition Assessment Manual, ORNL, October 2011 [12]. The overall CI

is a composite of the CI derived from each component of the turbine. This methodology can

be applied periodically to derive a CI snapshot of the current turbine condition such that it

can be monitored over time and studied to determine condition trends that can impact

performance and reliability.

The reliability of a unit as judged by its availability to generate can be monitored through

reliability indexes or performance indicators as derived according to NERC‘s Appendix F,

Performance Indexes and Equations [17].




Generation Control), but if not, hard copies of the curves and limits should be made available

to all involved personnel – particularly unit operators, their importance to be emphasized,

and their ability to be understood and confirmed.

Justified projects (hydraulic re-profiling, slot fillers, unit upgrade), and a method to

constantly monitor unit performance should be implemented.

As the condition of the turbine changes, the CI and reliability indexes are trended and

analyzed. Using this data, projects can be ranked and justified in the maintenance and capital

programs to bring the turbine back to an acceptable condition and performance level.


Baseline Knowledge:

Thomas C. Elliott, Standard Handbook of Powerplant Engineering, McGraw Hill Publishing,

1989

NEMA Standard for Hydraulic Turbines and Governors, Pub. No. HT1-1949

US Corps of Engineers, Hydro Plant Risk Assessment Guide, September 2006

EPRI, Increased Efficiency of Hydroelectric Power, EM 2407, June 1992

Hydroelectric Handbook, William P. Creager, John Wiley & Sons, 1950

USBR, FIST Volume 2-5, Turbine Repair, September 2000


Rev. 1.0, 12/06/2011

100

Hydro Life Extension Modernization Guide, Volume 2: Hydromechanical Equipment, EPRI,

Palo Alto, CA: 2000. TR-112350-V2.

State of the Art

March, P.A. and Wolff, P.J., Component Indicators for an Optimization-Based Hydro

Performance Indicator: HydroVision 2004, Montreal, Quebec, Canada, August 2004.

Brice, T.A. and Kirkland, J.E., Checking Turbine Performance by Index Testing, Hydro

Review, Vol. V, No. V, Winter, 1986

USACE, Turbine Surface Roughness Improvement, HDC-P, December, 2003

USACE, Stay Vane and Wicket Gate Relationship Study, CENWP- HDC-P, January 19, 2005

J.C. Jones, Wicket Gates – Grease vs. Greaseless, USBR O&M Workshop, April 10, 2001

ORNL, HAP Condition Assessment Manual, October, 2011

Spicher, T., Hydro Wheels: A Guide to Maintaining and Improving Hydro Units, HCI

Publications, 3rd

Edition 2004

Cateni, A., Margri, L., Grego, G.: Optimization of Hydro Power Plants Performance

importance of Rehabilitation and Maintenance in Particular for Runner – 2008

Standards:

ASME 2011, Hydraulic Turbines and Pump-Turbines, PTC 18-2011

IEC, 1991, Field Acceptance Tests to Determine the Hydraulic Performance of Hydraulic

Turbines, Storage Pumps and Pump-Turbines, IEC-60041

NERC, Appendix F, Performance Indexes and Equations, January, 2011

ASTM A487, Standard Specification for Steel Castings Suitable for Pressure Service

ASTM A743, Standard Specification for Castings, Iron-Chromium, Iron-Chromium-Nickel,

Corrosion Resistant, for General Application

http://www.asme.org/products/codes---standards/ptc-18---2011-hydraulic-turbines-and-pump-turbines

http://webstore.iec.ch/webstore/webstore.nsf/artnum/031323


http://www.nerc.com/


Kaplan/Propeller Turbine

Revision 1.0, 12/06/2011

HAP – Best Practice Catalog –Kaplan/Propeller Turbine

Rev. 1.0, 12/06/2011 102

1.0 Scope and Purpose ........................................................................................................... 103

1.1 Hydropower Taxonomy Position ................................................................................. 103

1.1.1 Propeller/Kaplan Turbine Components ................................................................ 103

1.2 Summary of Best Practices .......................................................................................... 105

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ..................... 105

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ................... 106

1.3 Best Practice Cross-references ..................................................................................... 107

2.0 Technology Design Summary .......................................................................................... 107

2.1 Material and Design Technology Evolution ................................................................ 107

2.2 State of the Art Technology ......................................................................................... 108

3.0 Operational & Maintenance Best Practices ..................................................................... 109

3.1 Condition Assessment .............................................................................................. 109

3.2 Operations .................................................................................................................... 114

3.3 Maintenance ................................................................................................................. 116

4.0 Metrics, Monitoring and Analysis ................................................................................... 122

4.1 Measures of Performance, Condition, and Reliability ................................................. 122

4.2 Data Analysis ............................................................................................................... 123

4.3 Integrated Improvements.............................................................................................. 123

5.0 Information Sources ......................................................................................................... 124


Rev. 1.0, 12/06/2011 103


This best practice for a Propeller/Kaplan turbine addresses its technology, condition assessment,

operations, and maintenance best practices with the objective to maximize its performance and

reliability. The primary purpose of the turbine is to function as the prime mover providing direct

horsepower to the generator. It is the most significant system in a hydro unit. How the turbine is

designed, operated, and maintained provides the most impact to the efficiency, performance, and

reliability of a hydro unit. The Propeller/Kaplan type turbine is typically used in a low head and

high flow application. Fixed-blade propeller types have a very narrow range of high efficiency

operation, while adjustable-blade types can operate at high efficiency over a wide flow and

power output range.


Hydropower Facility → Powerhouse → Power Train Equipment → Turbine →

Propeller/Kaplan Turbine

1.1.1 Kaplan/Propeller Turbine Components

Performance and reliability related components of a Propeller/Kaplan turbine consist of a

reaction type axial-flow runner with adjustable-blade mechanism, wicket gates and

controlling mechanism, spiral case, stay ring/stay vanes, and draft tube.

Spiral Case: The function of the spiral case (or scroll case) is to supply water from the

intake to the stay vanes, directly to the upstream portion of the turbine, and through a

unique shape of continual cross sectional area reduction to the downstream portion of the

turbine; maintaining a near uniform velocity of water around the stay vanes and wicket

gates.

Stay Ring/Vanes: The function of the stay vanes (and stay ring) is to align the flow of

water from the spiral casing to the wicket gates. They also function as support columns in

vertical units for supporting the static weight of the unit‘s stationary components and

hydraulic thrust during turbine operation.

Wicket Gates: The function of the wicket gates is primarily to control the quantity of

water entering the turbine runner, thereby controlling power output. Secondarily, the

gates control the angle of the high tangential velocity water striking the runner blades.

The optimum angle of attack will be at peak efficiency. In an adjustable-blade unit, the

tilt of the blades and opening of the gates are synchronized to maximize efficiency over

as much of the operating range as possible. The wicket gates also function as a closure

valve to minimize leakage through the turbine while it is shut down.

Runner: The function of the runner is to convert the potential energy of pressure (head)

and flow of water into mechanical energy or rotational horsepower. The Kaplan runner is

comprised of a hub, nosecone, blades, and an internal blade tilting mechanism - typically

a hydraulically-driven piston with linkage and seals. Oil pressure is provided by the

governor hydraulic system.


Rev. 1.0, 12/06/2011 104

Draft Tube: The function of the draft tube, which is initially conically shaped and

attached to the turbine discharge, is to gradually slow down the high discharge velocity

water, capturing kinetic energy from the water, which is usually below atmospheric

pressure. In most cases, it has an elbow in order to minimize excavation for the unit. The

head recovery from the draft tube is the difference between the velocity head at the

runner discharge and draft tube discharge, overall increasing the head across the turbine.

The larger the head differential is across the turbine, the higher the turbine power output.

The throat ring of the draft tube should be steel lined from the discharge ring to the point

where the water velocity reduces to about 20 ft/s, which is considered below concrete

scouring velocity [1].

Non-performance but reliability related components of a Propeller/Kaplan turbine include

the wicket gate mechanism/servomotors, head cover, bottom ring, turbine shaft, guide

bearing, mechanical seals/packing and discharge/throat ring.

Wicket Gate Mechanism/Servomotors: The function of the wicket gate mechanism and

servomotors is to control the opening and closing of the wicket gate assembly. The

mechanism includes arms, linkages, pins, shear pins, turnbuckles or eccentric pins for

closure adjustment, operating ring (or shift ring, and bearing pads), and bushings either

greased bronze or greaseless type. Servomotors are usually hydraulically actuated using

high pressure oil from the unit governor. In some limited cases a very small unit may

have electro-mechanical servomotors.

Turbine Shaft: The function of the turbine shaft is to transfer the torque from the turbine

runner to the generator shaft and generator rotor. The shaft typically has a bearing journal

for oil lubricated hydrodynamic guide bearings on the turbine runner end or wearing

sleeve for water lubricated guide bearings. Shafts are usually manufactured from forged

steel, but some of the largest shafts can be fabricated.


imbalance and hydraulic side loads from the turbine runner thereby maintaining the

turbine runner in its centered position in the runner seals. It is typically mounted as close

as practical to the turbine runner and supported by the head cover. Turbine guide bearings

are usually either oil lubricated hydrodynamic (babbitted) bearings or water lubricated

(plastic, wood, or composite) bearings.

Mechanical Seals / Packing: Water retaining sealing components in the turbine includes

the seal for the turbine shaft and the wicket gate stem seals. Shaft seals are typically

either packing boxes with square braided packing or for high speed units a mechanical

seal is required. Wicket gate stem packing is usually either a square braided

compression packing, a V type or Chevron packing, or some type of hydraulic elastomer

seal. Although in the truest sense any sealing components on a turbine could be a

performance issue, since any leakage that by-passes the turbine runner is a loss of energy,

the leakage into the wheel pit is considered insignificant to the overall flow through the

turbine.


Rev. 1.0, 12/06/2011 105

Oil filled Kaplan hubs have seals around the blade trunnions to prevent oil leakage and to

prevent water leakage into the oil. These trunnions seals are usually either double

opposing or chevron packing type.

Head Cover / Bottom Ring: The head cover is a pressurized structural member covering

the turbine runner chamber that functions as a water barrier to seal the turbine. It also

serves as a carrier for the upper wicket gate bushings, upper seal surface for the wicket

gate vanes, support for the gate operating ring, carrier for the runner stationary seal rings,

and support for the turbine guide bearing. The bottom ring serves as a carrier for the

bottom wicket gate bushings, bottom seal surface for the wicket gate vanes, and a carrier

for the bottom runner stationary seal ring.

Discharge / Throat Ring: The discharge ring serves as the steel housing of the runner

which is the transitional piece to the expanding draft tube.



Periodic testing to establish accurate current unit performance characteristics and

limits.

Dissemination of accurate unit performance characteristics to unit operators, local

and remote control and decision support systems, and other personnel and offices

that influence unit dispatch or generation performance.








made (e.g., hydraulic profiling, slot fillers, unit upgrade).

Trend loss of turbine performance due to condition degradation for such causes of

metal loss (cavitation, erosion and corrosion), opening of runner seal and wicket

gate clearances, increasing water passage surface roughness.


Include industry acknowledged ―up to date‖ choices for turbine components

materials and maintenance practices to plant engineering standards.


Rev. 1.0, 12/06/2011 106


Use ASTM A487 / A743 CA6NM stainless steel to manufacture

Propeller/Kaplan turbine runners, wicket gates, and water lubricated bearing

shaft sleeves to maximize resistance to erosion, abrasive wear, and cavitation.

Bushing clearances greater than two times the design are considered excessive

and warrants replacement.

Wicket gate shear pins (mechanical fuse) are an engineered product designed to

prevent failures of more costly components in the mechanism. When replacing

pins or spares pins, it is best practice, to purchase the pin material from one

manufacturer to ensure material properties remain consistent. Prototype sample

pins are manufactured and tested to finalize the diameter for the final pin shop

drawing.

Turbine shaft areas near the shaft seal that are exposed to water should be sealed

with a robust coating such as an epoxy paint to prevent corrosion of the shaft.


using 309L stainless steel welding electrodes. The electrodes increase damage

resistance.

Propeller/Kaplan turbines with heads above 100 feet should be considered as

candidates for embedded wicket gate vane end seals and wicket gates fabricated

from stainless steel to mitigate leakage and wear.



Vacuum breakers should be inspected routinely and adjusted for optimal

performance.

Discharge areas on a turbine runner for aeration devices should be clad with

stainless steel to mitigate cavitation.

Wicket gate mechanism linkage bushings should be of the greaseless type to

reduce grease discharge to the wheel pit and ultimately the station sump. Using

greaseless bushings in other applications possible; however, care must be taken

in any retrofit to ensure that the servomotors are of sufficient strength to operate

even after a 25% increase in long term friction.





Rev. 1.0, 12/06/2011 107









Propeller/Kaplan turbine blades and internal parts are typically cast; whereas the hub and

nose cone are either cast or rolled and welded. Very old runners, from the early 1900‘s or

before, could have been cast from cast iron, later replaced with cast carbon steel. Today‘s

casting would involve casting or fabrication from carbon steel or stainless steel. As a best

practice, the most common material used for the blades is ASTM A487/A743 CA6NM

stainless steel [18, 17]. It is cavitation-resistant, fairly easy to cast and fabricate, and can

usually be weld-repaired without post heat treatment.












commissioning.






to new turbine design information from manufacturers to establish the achievable unit



Rev. 1.0, 12/06/2011 108


Turbine efficiency is likely the most important factor in a condition assessment to determine

rehabilitation or replacement. Testing may show performance has degraded significantly. For

example the efficiency of a Kaplan unit has experienced steady degradation amounting to a

total of 4 percentage points over a 19 year period (Figure 1).

Figure 1: Kaplan Performance Degradation

Regardless of whether performance has degraded or not, newer turbine designs are usually

more efficient than those designed 30 to 40 years ago. Also, a new turbine can be designed

using actual historical data rather than original design data providing a turbine more

accurately suited for the site. Newer turbine designs also provide decreased cavitation based

on better hydraulic design and materials [2]. For comparison, Figures 2 and 3 show an

original runner and its stainless steel replacement runner.

2,000

6,000

10,000

14,000

18,000

22,000

26,000

30,000

34,000

55

60

65

70

75

80

85

90

95

5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Tu

rbin

e D

isch

arg

e -

cfs

Tu

rbin

e E

ffic

ien

cy -

%

Turbine Output - hp

Off-Cam 2004

Optimum Cam 2004

1985

1997


Rev. 1.0, 12/06/2011 109

3.0 Operational & Maintenance Best Practices


After the commercial operation begins, how the turbine is operated and maintained will have

a huge impact on loss prevention of the IPL and CPL and maintaining reliability.

Materials for turbine runners are usually cast iron, steel, or stainless steel. As a best practice,

the most common material being used today for new state of the art runners is ASTM A487 /

A743 CA6NM stainless steel [16, 17]. It is cavitation resistant, fairly easy to cast and

fabricate, and can usually be weld repaired without post heat treatment.

The same is true for wicket gate materials. The hub and nose cone are usually carbon steel,

but should have strategically-located stainless steel overlay. The other wetted components

such as distributor rings, including stay vanes, are typically constructed from steel due to

strength requirements and some with stainless steel cladding overlaid in critical areas.

Spiral cases and draft tubes are usually left as poured concrete except for the high velocity

throat ring area. A significant contributor to performance loss in these wetted components is

any surface degradation due to cavitation, abrasive erosion, surface finish degradation, and

the poor quality of past repairs. Typical locations are shown in Figure 4. These deteriorating

factors can distort the hydraulic design contours of components. Condition assessment of

those flow components must address all past damage, location of damage, repeat damage,

and resulting increase in surface roughness. The same is true for wicket gate materials.

The other wetted turbine components such as stay vanes, spiral cases, and draft tubes are

usually constructed from steel due to strength requirements. Some components have

stainless steel cladding overlaid in critical areas. The most significant contributor to

performance loss for all wetted components is any metal loss due to cavitation, as shown in

Figure 4, abrasive erosion, surface finish degradation, and the poor quality of past repairs

which can distort the hydraulic design contours of components.

Figure 2: Original Runner

Figure 3: New Stainless Replacement Runner


Rev. 1.0, 12/06/2011 110

Condition assessment of those flow components must address any past damage, location of

damage, repeat damage, and resulting increase in surface roughness.

Figure 4: Typical Areas to Check for Cavitation Damage

A certain amount of cavitation is inherent in a Kaplan runner, primarily due to gaps between

the blade inner periphery and hub, and between the blade outer periphery and throat ring.

Most runners manufactured since the 1980‘s include an ―anti-cavitation fin‖ (located on a

portion of the suction side of the blade outer periphery) to serve as a sacrificial element

(Figure 5). Periodic inspection of this fin and of the throat ring may assist in identification of

excessive operation beyond recommended cavitation limits in an effort to take advantage of

the excessive flow and/or head which are otherwise wasted.


Rev. 1.0, 12/06/2011 111

Figure 5: Anti-Cavitation Fin & Throat Ring Overlay

A comparison of the blade tip clearances to original installation measurements will provide

an indication of the condition of the mechanism (bushings/bearings) securing the blade

trunnions. Increased play in the securing mechanism of the trunnions can result in sagging

blade tips which essentially creates a modified hydraulic profile from that designed, and

consequent reduction in performance.

Drifting of the blade position over time and excessive oil usage may indicate the need to

replace piston rings or other oil seals in the system. Maintaining blade position is paramount

for optimizing performance. A periodic check should be made of the blade position on the

hub versus the indicated position outside the unit, since original manufacturer‘s data (usually

model) is often required to develop the optimum gate-blade relationship over the full head

range.

Evaluating the condition of a turbine and its components may show that a new, state of the

art designed runner with enhanced power and efficiency may provide sufficient benefits to

justify its replacement, including rehabilitating related components, as compared to

maintaining the current turbine with its existing efficiency [2].

The wicket gate mechanism (Figure 6) and the actuating servomotors provide for the

regulation and control of the turbine. The condition assessment of the components would

include measurements of wear or looseness in the arms, linkages, pins, shear pins,

turnbuckles (or eccentric pins), linkage bushings, operating ring (and bearing pads), and


Rev. 1.0, 12/06/2011 112

wicket gate stem bushings. It is important to note, that excessive wear in the components is

additive and can result in losing off-line regulating control of the wicket gates making it

more difficult to synchronize the unit. This is an indicator that rehabilitation on the

components is necessary. Measurement of wear is difficult without disassembly, however,

extreme wear can be observed as loss of motion in gate movements.

In some turbine designs it is possible during un-watered outages, to measure the clearance

between the wicket gate stem journals and the inside diameter of the bushings with feeler

gauges. Abnormal water leakage around the wicket gates in the turbine wheel pit after an

attempt to adjust the stem packing is an indicator of excessive wicket gate stem bushing

wear. As a best practice, bushing to journal clearance greater than two times the design is

considered excessive. An increase in the number of shear pin failures over a given period is

an indication of either a problem with the design and material used to manufacture the pins or

binding in the mechanism.

Figure 6: Wicket Gate Mechanism

Hydraulic servomotors (Figure 7) are usually very reliable, with the most common problem

being oil leakage from the seal on the actuating rod. The amount of acceptable leakage is

dependent on the seal design and site maintenance requirements. Hydraulic seals will leak

very little whereas a square braided compression packing will leak more.

A condition assessment would include observation of the leakage and discussion with the

plant maintenance technicians as to the amount of daily or weekly maintenance required.

Excessive maintenance would require the change of the seal or packing. It is important to

note and observe if the actuating rod is smooth, without any scoring or grooves which would

prevent sealing. If the rod is damaged it will require repair or replacement.


Rev. 1.0, 12/06/2011 113

Figure 7: Wicket Gate Servomotor

The condition assessment of the head cover and bottom ring consists mainly of visually

inspecting the wetted surfaces for erosion and cavitation. Cracking in either component or

deep erosion in the water barrier of the head cover is a major concern and must be addressed

immediately. Excessive corrosion of the joint bolting (stay ring flange or split joints) or

failure of the bolting is a major concern and must be addressed immediately. The assessment

would also include observation of any galling between the ends of the wicket gate vanes and

the head cover and bottom ring and damage to embedded end seals.

The condition assessment of the turbine shaft (Figure 8) would include observation of

corrosion and defects on the exposed surface. Any cracking as identified by the

Nondestructive Examination (NDE) methods is a major concern and must be addressed

immediately. Bearing journals and sleeves must be smooth and free of defects (only

accessible with bearing removed) to ensure the reliability of the turbine guide bearing. As a

best practice for water lubrication, turbine bearings, wearing sleeves are usually

manufactured from ASTM A743 CA6NM [17] stainless steel either as a forging or

centrifugally cast. Areas near the shaft seal that are exposed to water should be sealed with a

robust coating such as an epoxy paint to prevent corrosion of the shaft.

Figure 8: Turbine Shaft / Wheel Pit


Rev. 1.0, 12/06/2011 114

Turbine guide bearings are usually either oil lubricated hydrodynamic bearings (Figure 9) or

water lubricated bearings (Figure 10), with the latter being found only in low head slow

speed units. The condition assessment of the oil lubricated type includes vibration

measurements (i.e. shaft throw) and temperature of the bearing in operation. Abnormal

indications of those could be a sign of failure of the babbitted surface (wipe), un-bonding of

the babbitt from the bearing housing, or contamination of the oil.

The condition assessment of a water lubricated type, centers mainly on vibration

measurements and success of subsequent bearing adjustments (design permitting). An

indication of a loose wearing sleeve on the shaft is excessive shaft throw (vibration) even

after adjusting the bearing. Non-adjustable water lubricated bearings, or bearings worn

beyond adjustment will require the wearing liner (either wood, plastic, or composite) to be

replaced.

Figure 9: Babbitted Oil Journal Bearing

Figure 10: Water Lubricated Bearing

The condition assessment of the wicket gate stem seals or shaft seals usually includes the

observation of excessive water leakage in the turbine wheel pit area which can be viewed

visually or estimated by sump pump operation (if available). Excessive leakage, even after

adjustments (if possible by design), is an indication that the seals or packing must be

replaced.

Either leakage of oil from the Kaplan blade trunnions seals or leakage of water into the

Kaplan hub, oil condition is an indicator of possible worn Kaplan blade trunnions bushings

or bearings. Excessive wear in the blade trunnions bushings allow the blade to move further

than the capability of the seal resulting in leakage during operation and long term wear of the

seal.

3.2 Operations

Turbine performance can be maximized by utilizing operating characteristic curves and

adhering to minimum and maximum output limits (such as vibration and cavitation).

Adjustable-blade units require the additional necessity of an accurate gate-blade relationship.

Curves, limits, and gate-blade relationships should be generated from manufacturer‘s data

and adjusted to field test data.


Rev. 1.0, 12/06/2011 115

Operation will only be as good as this information is accurate. Plus, the performance of the

turbine can degrade over time due to cavitation and/or erosion damage and resulting weld

repairs, etc. Periodic performance checks, through absolute or relative (e.g., index) testing,

are necessary for maintaining accuracy, and must be made comprehensively at a number of

operating heads. If a 2-dimensional (2D) cam is used in the governor for blade tilt control, it

must be adjusted periodically to changing head conditions. If an electronic 3-dimensional

(3D) cam is used, the database must be updated as needed, and the head inputs must checked

against independent measurements particularly if the permanent measurement location can be

affected by trash buildup.

Figure 11 shows typical performance curves for fixed and adjustable-blade units (in this case,

from the same plant). The very narrow range of high efficiency in the fixed blade units must

be defined accurately to optimize performance. In contrast, the adjustable-blade units offer a

much wider range of high efficiency; however, the absolute peaks of the individual blade tilt

efficiency curves (Figure 1) must be defined accurately in order to develop the optimum

gate-blade relationships required to realize optimum performance.

Figure 11: Typical Fixed and Adjustable-Blade Unit Efficiency Curves

Frequent index testing, especially before and after major maintenance activities on a turbine,


controls. [5] Plants should, ―as best practice‖, perform periodic performance testing (such as

index testing according to PTC 18 [14] to assure the most accurate operating curves are

available to optimize plant output. This should be done on a 10 year cycle, as a minimum.

Pressures in the draft tube increase as the water flows from the elbow to the exit. If the top of

the draft tube gate slots are submerged (under tailwater), water can be drawn down into the

65

70

75

80

85

5 10 15 20 25 30

Ov

era

ll E

ffic

ien

cy (

%)


Fixed Blade 1 Fixed Blade 1 Adjustable Blade 1

Adjustable Blade 2

Fixed Blade 1

Fixed Blade 2


Rev. 1.0, 12/06/2011 116

draft tube due to the lower pressure there, increasing the total flow in the draft tube from that

point to the exit, thereby increasing the head loss and reducing the unit efficiency. The closer

the gate slot is to the centerline of the unit, the greater the effect. The use of slot fillers to

plug the upper openings of the gate slots (Figure 12) have been shown to remedy this

problem in one case by as much as 1% efficiency [7].

Figure 12: Draft Tube Gate Slot Fillers

3.3 Maintenance


performance over time (in default of restorative action) [3]. Usual causes include cavitation

damage, abrasive erosion wear, galvanic corrosion, striking damage from debris passing

through, and errors in welding repairs to original blade profiles and surface finish.

Performance-related maintenance techniques involve mainly those weld repairs to cavitation

damage, abrasive erosion damage, and galvanic corrosion on the turbine components such as

the runner, wicket gates, and distributor ring. Usual best practice is to perform cladding with

a 309L stainless steel welding electrode to provide some cavitation resistance. In some cases,

original blade contour templates are available at the plant to facilitate returning the blade

inlet and trailing edges back to OEM specifications. A good reference for turbine

maintenance is the USBR‘s FIST Volume 2-5, Turbine Repair [4] and Spicher‘s Hydro

Wheels [13].

Typically, Kaplan runner blades are designed with stress relief grooves at the leading and

trailing sides of the blade/trunnion intersection (Figure 13). These grooves, located to

minimize the possibility of cracking in the high stress areas of the blade, create cavities in the

flow profile which cause downstream disturbances in the form of low pressure vortices and

can result in cavitation erosion on the hub and nose cone. It has been shown that fillers,

attached to the blade or trunnion seal, have been effective in reducing the erosion, especially

when paired with strategically-located stainless steel overlay on the hub and nose cone.

Figure 14 shows a typical overlay area for a Kaplan runner hub/nose cone. Also, the

spherical design of some newer runner hubs, as opposed to the traditional conical design,

minimizes the gap between the blades and hub as the blades move to flatter positions

(Figures 2 and 3).


Rev. 1.0, 12/06/2011 117

Additional areas for stainless steel overlay include the throat ring to protect against ―seal

cavitation‖ at the blade periphery (Figure 5), and sections of the lower distributor ring and

bottom ring where Von Karman vortices can trail off the wicket gates during high flow

operation (Figure 15).

Flow profile modifications, a narrowing of the lower trailing edges of the wicket gates

(Figure 16), can reduce vortices and allow higher flow rates and power output. The exact

profile change should be designed based on Computational Fluid Dynamics (CFD) and/or

physical modeling.

Figure 15: Bottom Ring Overlay

Figure 16: Modified Wicket Gate

Figure 13: Stress Relief Notch & Overlay

Figure 14: Typical Hub/Nose Cone Stainless Steel

Overlay Location


Rev. 1.0, 12/06/2011 118

Investigations by the US Army Corps of Engineers (USACE) show minor modifications to

the stay vane/wicket gate system could result in an operation efficiency increase of 0.5 to

0.7% for units studied [8]. As shown in the reference, the modification takes the form of

profile changes on the stay vane, leading and trailing edges, modifying the wake relative to

the wicket gate. The exact profile change should be designed based on CFD and/or physical

modeling. In addition, such modifications can reduce fish injury as one environmental

benefit.

Worn wicket gate end clearances can also contribute to a decline in unit performance since

leakage contributes to power generation loss, particularly by those units with a low service

factor (i.e., gates in closed position a significant period of time). In a new unit, the leakage

through properly designed wicket gates may be markedly less than 1% of full gate discharge,

however, over years of operation this could be doubled due to eroded end clearances, worn

stem journal bushings, and improperly adjusted toe to heel closures.

The wicket gate mechanism consists of arms, linkages, pins, shear pins, turnbuckles (or

eccentric pins), linkage bushings, operating ring (and bearing pads), and wicket gate stem

bushings. For greased bushing designs it is essential that the greasing system is functioning

to original specification with metered grease flowing to all points. It is important to grease

the wicket gate stem bushings and observe if the grease is entering the bushing clearance and

visually discharging. If not, this will have to be repaired immediately.

Greaseless bushing designs require less routine maintenance than the greased designs;

however the most common maintenance issue is broken or loose anti-rotation devices on the

pins. The greaseless bushings will wear at a more rapid rate than the greased bushings,

requiring replacements more frequently, such as on a 10 to 20 year cycle in contrast to a 30

to 40 year cycle for greased bushings.

As a best practice, the bushings on the wicket gate linkages are usually the greaseless type in

order to reduce the amount of grease discharging into the wheel pit area and ultimately

flowing into the powerhouse sump. Bushing applications in other turbine areas, such as

wicket gate stem bushings, operating ring pads, and servomotors are usually chosen based on

the owner‘s preference when comparing bushing life and reliability versus the owner‘s desire

to minimize the use of grease lubrication. However, it is important that each greaseless

bushing is designed correctly for the application.

In some cases the friction in greaseless bushings increases over time due to trapped wear

debris and incursion of silt and debris from the water, as compared to the greased bushings

which are flushed by the movement of the grease. An increase in long term operating

friction in greaseless applications means the wicket gate servomotors must be over designed

(particularly in retrofits) with excess capacity of at least 25% in order to ensure reliable

operation [10].

Major maintenance of the wicket gate mechanism includes replacement of the pins, pads,

bushings, and true machining of wear surfaces. This will be required every 10 to 40 years

depending on the design and operating conditions. Shear pins (mechanical fuse) are an

engineered product designed to prevent failures of more costly components in the


Rev. 1.0, 12/06/2011 119

mechanism. It is best practice to purchase the pin material from one manufacturer to ensure

material properties remain constant. Prototype sample pins are manufactured and then

broken in a test stand to determine actual shear properties. This test data is used to finalize

the shear area diameter for the final pin shop drawing.

Routine maintenance of wicket gate servomotors is minimal and usually only requires

changing of the actuating rod seals or packing when leakage become excessive. Major

maintenance includes an overhaul of the servomotor, requiring disassembly, and replacement

of bushings, seals, and piston rings.

Further studies by the USACE to improve turbine efficiency have found some relationship

between surface roughness of the turbine components, and degradation of the unit

performance [9]. It is commonly known that surface roughness on flow surfaces robs a

moving fluid of energy; similar to what is found in piping systems. A higher relative

roughness will increase the friction loss usually in the head pressure.

Since the power generated by a turbine is directly related to head, logically, any loss in head

by frictional losses of the water flowing through the turbine will be a loss in performance.

Improvements in surface finish include grinding and coating (painting) the surfaces. In some

cases, the USACE tests found efficiency improvements of 0.1 to 0.8% comparing pre-coated

versus post-coating performance [9]. However, the level of uncertainty of field testing

measurement can range up to 1%, which makes it difficult to quantify results within testing

error. Common maintenance best practice of providing adequate coating of the turbine

components to prevent surface corrosion does have added benefits of improved performance,

however unquantifiable.

Figure 17: Draft Tube Modification

At certain head and flow rate combinations, flow separation can occur in the elbow section of

some draft tubes resulting in unstable operation (stall). This is manifested in scattered data


Rev. 1.0, 12/06/2011 120

forming steep, peaky efficiency curves for individual blade tilts which make it difficult to

determine and maintain an optimum gate-blade relationship. A reduction in the cross-

sectional area of the elbow can reduce separation and be accomplished economically by

strategically pouring concrete to raise the floor elevation (Figures 17 and 18).

Exact pour locations and depths should be determined using CFD and/or physical modeling.

The result is more rounded efficiency curves so that if the gate-blade relationship changes,

the operation will shift only slightly lower in efficiency instead of nose-diving. Additionally,

model tests for one project showed efficiency and capacity gains of 0.11% and 535 hp.

Figure 18: Draft Tube Mod Pour

In general, any potential modifications to hydraulic profiles should be studied and verified

with CFD and/or physical modeling by a competent turbine manufacturer or independent

hydraulic laboratory. In the event of model testing for a turbine upgrade, the opportunity

should be taken to investigate any modifications that hold performance improvement

potential.

Head cover and bottom ring routine maintenance is usually to ensure that the protective

coating on the wetted surfaces is intact and any erosion or cavitation is repaired before it

progressively worsens. Any galling damage at or near the ends of the wicket gate vanes

must be removed by grinding to prevent further galling or damage to the wicket gate vane

end seals.

It is imperative that the design of wicket gate up thrust device be robust to resist the axial

movement of the gate and prevent the gate from contacting the headcover. Wicket gate up

thrust is generated either by the hydraulic pressure of water under the bottom stem and/or

grease application pressure. Major maintenance of the head cover and bottom ring includes

blasting and NDE for cracking inspection, recoating, and replacing wear plates and runner

stationary seal rings, and replacing wicket gate bushings.


Rev. 1.0, 12/06/2011 121

Routine turbine shaft maintenance consists of minimizing the corrosion of the shaft surface

with a light coat of oil in the non-water contact areas and periodic re-coating of areas that

come in contact with water with a robust paint such as epoxy. Major maintenance includes

refurbishment on bearing journals, or replacement of wearing sleeve, and re-truing coupling

faces during a major unit overhaul.

Turbine guide bearings are usually either oil lubricated hydrodynamic bearings or water

lubricated bearings. Maintenance of an oil lubricated bearing and its reliability is directly

connected to the quality of the supplied oil used for lubrication and cooling. Any

contamination of the oil either with debris or water will increase the likelihood of a bearing

failure. A best practice is to install a kidney loop filtration system capable of continuously

removing debris and water from the bearing oil supply.

Maintenance of a water lubricated bearing and its reliability is also directly connected to the

quality of the supplied water used for lubrication and cooling. Although in this case, with the

viscosity of the water being so low, the water functions more as a coolant than as a lubricant.

A best practice is to install an automatic strainer with internal backwash for uninterrupted

supply of clean water to the bearing without need of routine maintenance to change or clean

the filters. An uninterrupted supply is essential since any loss of water flow during turbine

operation will quickly overheat the anti-friction contact surface of the internal liner (plastic,

wood, or composite) of the bearing resulting rapid failure.

Since water lubricated bearings inherently wear which results in an increase is shaft vibration

(shaft throw), periodic maintenance is required to adjust the bearing to tighten the running

clearance. Some poorly designed bearings are non-adjustable and require the internal lining

to be replaced every time. Extreme shaft vibration can cause contact of the turbine runner‘s

seal rings, resulting in wear and the possible failure of the seal rings causing extended unit

outage. Major maintenance of either bearing type requires the refurbishment of the bearings,

such as re-babbitting of an oil bearing or re-lining the water lubricated bearing. In addition,

for the water lubricated bearing, the shaft wearing sleeve may have to be machined true or

replaced.

Sealing components in the turbine include the wicket gate stem seals and the seal for the

turbine shaft. Routine maintenance will vary according to the type of seal and the operating

conditions. Generally the hydraulic type seals, such as PolyPak seals, on wicket gate stems

are maintenance free, however, like o-ring seals, once they leak there are no adjustments and

must be replaced. Adjustable seal designs, such as with packing, can be tightened to reduce

the leakage. Excessive leakage, even after adjustment, is an indication that the seals or

packing must be replaced.

Seals for the turbine shaft vary from simple packing in a packing box around the shaft to

higher speed applications with mechanical seals. It is important to note that a certain amount

of leakage is required in a turbine shaft seal for cooling the seal (or packing), therefore zero

leakage is not the objective. Routine maintenance includes replacement of the packing in the

packing box or replacement of the composite (sacrificial) wearing component in the

mechanical seal. Major maintenance of all the applications consists of the routine

maintenance replacements and additional replacement of and opposing hard face wear


Rev. 1.0, 12/06/2011 122

elements such as wear sleeves for packing and hard face wear elements for the mechanical

seals.

Kaplan blade trunnions seals usually require replacing every 15 to 20 years. However, after

40 to 50 years the Kaplan blade trunnions bushing or bearings may be worn to the extent that

seal replacements will not retain oil or water. At this point the Kaplan turbine will require

refurbishment or replacement.



The fundamental process for a hydro turbine is described by the efficiency equation, defined

as the ratio of the power delivered by the turbine to the power of the water passing through

the turbine.








Turbine performance parameters for Propeller/Kaplan units are defined in ASME PTC-18

[14] and IEC 60041 [15], and typically include the following: Generator Output, Turbine

Discharge, Headwater and Tailwater Elevations, Inlet Head, Discharge Head, Gate Position,

Blade position, and Water Temperature.


generator bearings, and headcover and thrust bridge displacements (z). Acoustic emission (on

the draft tube man-door or liner) may be measured to track relative cavitation noise.

During unit outages: Blade tip clearances.

The condition of the Propeller/Kaplan turbine can be monitored by the Condition Indicator

(CI) as defined according to HAP Condition Assessment Manual [12].




(EFOR). These are universally used by the power industry. Many utilities supply data to the


operating information is used for improving the performance of electric generating

equipment. It can be used to support equipment reliability and availability analysis and

decision-making by GADS data users.


Rev. 1.0, 12/06/2011 123

4.2 Data Analysis

Analysis of test data is defined in ASME PTC-18 [14] and IEC 60041[15]. Basically, the

analysis is used to determine unit efficiency and available power output relative to turbine

discharge, head, gate opening, and blade tilt position. Determine operating limits based on

vibration and acoustic emission measurements (CPL). Compare results to previous or

original unit test data (IPL), and determine efficiency, capacity, annual energy, and revenue

loss. Compare results to new unit design data (from turbine manufacturer), and determine

potential efficiency, capacity, annual energy, and revenue gain (PPL). For the latter, calculate

the installation/rehab cost and internal rate of return to determine upgrade justification.

Separately determine justification of any modifications (e.g., draft tube profile) using turbine

manufacturer‘s data.

Determine the optimum gate-blade relationship. Compare the current 2D cam adjustment

practice to a seasonal or periodic adjustment, and calculate the associated energy and revenue

difference. Compare the current 2D cam adjustment practice to the continuous adjustment of

a 3D cam, and calculate the associated annual energy and revenue gain. For the latter,

calculate the 3D cam installation cost and internal rate of return to determine upgrade

justification.

Trend blade tip clearances relative to OEM design values. If rehab is required (resulting in

complete unit disassembly), consider value of installing new design unit.




The condition assessment of a Propeller/Kaplan turbine is quantified through the Condition

Indicator (CI) as derived according to HAP Condition Assessment Manual [12]. The overall

CI is a composite of the CI derived from each component of the turbine. This methodology

can be applied periodically to derive a CI snapshot of the current turbine condition such that

it can be monitored over time and studied to determine condition trends.



Performance Indexes and Equations, January 2011 [15].



limits. Optimally, these would be integrated into an automatic system (e.g. Automatic

Generation Control, AGC), but if not, hardcopies of the curves and limits should be made

available to all involved personnel, particularly unit operators , their importance to be

emphasized, and their ability to be understood and confirmed.

If required, 2D cams should be replaced or re-profiled and 3D cam databases updated to

reflect the test results. A table or set of curves showing the gate-blade relationship should be

available to all involved personnel for periodic checking.


Rev. 1.0, 12/06/2011 124

Justified projects (hydraulic profiling, slot fillers, unit upgrade), and a method to constantly

monitor unit performance should be implemented.





Baseline Knowledge:

Thomas C. Elliott, Standard Handbook of Powerplant Engineering, McGraw Hill Publishing,

1989.

US Army Corps of Engineers, Hydro Plant Risk Assessment Guide, September 2006.

EPRI, Increased Efficiency of Hydroelectric Power, EM 2407, June 1992.

USBR, FIST Volume 2-5, Turbine Repair, September 2000


Palo Alto, CA: 2000. TR-112350-V2.

State of the Art:

Brice T.A. and Kirkland J.E., Checking Turbine Performance by Index Testing, Hydro

Review, Vol. V, No. V, Winter 1986.

March, P.A. and P.J. Wolff, Component Indicators for an Optimization-Based Hydro

Performance Indicator, HydroVision 2004, Montreal, Quebec, Canada, August 2004.

TVA and Principia Research Corporation, Hydroturbine Acceptance Tests for the Unit

Replacement Runner at Ft. Patrick Henry Hydro Plant, November, 1999.

USACE, Stay Vane and Wicket Gate Relationship Study, CENWP- HDC-P, January 19,

2005.

USACE, Turbine Surface Roughness Improvement HDC-P, December, 2003.

Jones, J.C. Wicket Gates – Grease vs. Greaseless, USBR O&M Workshop, April 10, 2001





Publications, 3rd

Edition 2004

Standards:

ASME PTC 18, Hydraulic Turbines and Pump-Turbines, Performance Test codes – 2002


Rev. 1.0, 12/06/2011 125

IEC International standard 60041, Field Acceptance Tests to Determine the Hydraulic

Performance of Hydraulic Turbines, Storage Pumps and Pump-Turbines - 1991 3rd Ed.


ASTM A743, Standard Specification for Castings, Iron-Chromium, Iron-Chromium-Nickel,

Corrosion Resistant, for General Application

ASTM A487, Standard Specification for Steel Castings Suitable for Pressure Service


Pelton Turbine

Revision 1.0, 12/06/2011

HAP – Best Practice Catalog – Pelton Turbine

Rev. 1.0, 12/06/2011 127



1.1.1 Pelton Turbine Components ................................................................................. 128


1.2.1 Performance/Efficiency and Capability - Oriented Best Practices .................. 130

1.2.2 Reliability/Operations and Maintenance - Oriented Best Practices ................ 131





3.0 Operation and Maintenance Practices .............................................................................. 133

3.1 Condition Assessment .................................................................................................. 133

3.1.1 Runner .................................................................................................................. 134

3.1.2 Housing/Discharge Chamber .............................................................................. 135

3.1.3 Nozzle ................................................................................................................... 136

3.1.4 Distributor/Manifold ........................................................................................... 138

3.2 Operations ................................................................................................................. 139

3.3 Maintenance ................................................................................................................. 140

3.3.1 Weld Repair ......................................................................................................... 140

3.3.2 Grinding Template .............................................................................................. 140

3.3.3 Surface Coating ................................................................................................... 140

3.3.4 Turbine Shaft ........................................................................................................ 140

3.3.5 Guide Bearings ..................................................................................................... 141



4.2 Data Analysis ............................................................................................................... 142




Rev. 1.0, 12/06/2011 128


This best practice for a Pelton turbine addresses its technology, condition assessment, operations,

and maintenance best practices with the objective to maximize its performance and reliability.

The purpose of the turbine is to function as the prime mover providing direct horsepower to the

generator. It is the most significant system in a hydro unit. How the turbine is designed,

operated, and maintained provides the most significant impact on the efficiency and performance

of a hydro unit.


Hydropower Facility Powerhouse Power Train Equipment Turbine Pelton

Turbine

1.1.1 Pelton Turbine Components

Pelton turbines are impulse turbines used for high head (usually 100 to 1000 m or above)

and low flow hydro applications. The Pelton runner normally operates in air or near

atmospheric pressure with one to six jets of water impinging tangentially on the runner.

The Pelton turbine units come in two shaft axis arrangements: horizontal (Figure 1) and

vertical (Figure 2). This is dictated by the overall hydro plant design. The horizontal shaft

turbine (maximum of 4 jets) is simpler to perform maintenance, but the powerhouse is

larger in size, whereas the vertical shaft turbine (maximum of 6 jets) is more difficult to

perform maintenance but allows a narrower shape of the power station footprint [1].

Figure 1: Twin runner horizontal Pelton turbine


Rev. 1.0, 12/06/2011 129

Figure 2: Multi-nozzle vertical Pelton turbine

Performance and reliability related components of a Pelton turbine consist of a

distributor/manifold, housing, needle jet/nozzle, impulse runner and discharge chamber.

Distributor/Manifold: The function of the distributor (or manifold) is to provoke an

acceleration of the water flow towards each of the main injectors. The advantage of

this design is to keep a uniform velocity profile of the flow.

Housing: The function of the housing is to form a rigid unit with passages for the

needle servomotor piping, feedback mechanisms, and the deflector shafts. The shape

of the wetted side of the housing is important for directing the exit water effectively

away from the runner.

Needle Valve/Nozzle: The function of the needle jet (or nozzle) is to regulate the flow

of water to the runner in an impulse turbine runner. The needle jet is regulated by the

governor via mechanical-hydraulic or electro-hydraulic controls. The shape is

designed for rapid acceleration at the exit end and for assuring a uniform water jet

shape at all openings. The needle valve/nozzle assembly is placed close to the runner

as possible to avoid jet dispersion due to air friction [2].

Runner: The runner consists of a set of specially shaped buckets mounted on the

periphery of a circular disc. It is turned by forced jets of water which are discharged

from one or more nozzles. The resulting impulse spins the turbine runner, imparting

energy to the turbine shaft. The buckets are split into two halves so that the central

area does not act as a dead spot (no axial thrust) incapable of deflecting water away

from the oncoming jet [2].

Discharge Chamber: The function of the discharge chamber is to enable water

existing the runner to fall freely toward the drainage. It also functions as a shield for

the concrete work and avoids concrete deteriorations due to the action of the water


Rev. 1.0, 12/06/2011 130

jets. Correct water level regulation (surge chambers) inside this chamber is critical for

maximum efficiency.

Non-performance but reliability related components of a Pelton turbine include the

deflector, turbine shaft, and guide bearing.

Deflectors: The deflectors have the function to bend the jet away from the runner at

load rejections to avoid too high of a speed increase. Moreover it protects the jet

against exit water spray from the runner. The deflector arc is bolted to the deflector

support structure frame with the control valve of the needle servomotors. A seal ring

around the deflector shaft bearing housing prevents water and moisture from

penetrating into the bearing.

Turbine Shaft: The function of the turbine shaft is to transfer the torque from the

turbine runner to the generator shaft and rotor. The shaft typically has a bearing

journal for oil lubricated hydrodynamic guide bearings on the turbine runner end.

Shafts are usually manufactured from forged steel, but some of the larger shafts can

be fabricated.


imbalance and hydraulic side loads from the turbine runner, thereby maintaining the

turbine runner in its centered position in the runner seals. It is typically mounted as

close as practical to the turbine runner and supported by the head cover. Turbine

guide bearings are usually oil lubricated hydrodynamic (babbitted) bearings.


1.2.1Performance/Efficiency and Capability - Oriented Best Practices

Periodic testing to establish accurate current unit performance characteristics

and limits.


local and remote control and decision support systems, and other personnel and

offices that influence unit dispatch or generation performance.








made (e.g., hydraulic profiling, unit upgrade, etc.).


Rev. 1.0, 12/06/2011 131

Trend loss of turbine performance due to condition degradation for such causes

as metal loss (cavitation, erosion, and corrosion), opening of runner seal, and

increasing water passage surface roughness.

Include industry acknowledged advances for updated turbine component



1.2.2Reliability/Operations and Maintenance - Oriented Best Practices

Use ASTM A743 CA6NM stainless steel to manufacture Pelton turbine runners,

and water lubricated bearing shaft sleeves to maximize resistance to erosion,

abrasive wear, and cavitation. [15]


using 309L stainless steel welding electrodes to increase damage resistance.

The electrodes increase damage resistance.






Monitor trends for the condition of turbine for decreasing Condition Indicator

(CI) and decrease in reliability, that is to say an increase in Equivalent Forced

Outage Rate (EFOR) and a decrease in Effective Availability Factor (EAF).




Mechanical - Lubrication System Best Practice





Rev. 1.0, 12/06/2011 132



Pelton turbine runners are typically manufactured as one piece, either as a casting or as a

welded fabrication. Very old runners, from the early 1900‘s or before, could have been cast

from cast iron or bronze, later replaced with cast carbon steel. Today they are either cast or

fabricated from carbon steel or stainless steel. Just as materials have improved for modern

turbine runners, so has the design and manufacturing to provide enhanced performance for

power, efficiency, and reduced cavitation damage.












commissioning.






to new turbine design information from manufacturers to establish the achievable unit



Turbine efficiency is likely the most important factor in an assessment to determine

rehabilitation or replacement of the turbine. Such testing may show CPL has degraded

significantly from IPL. Figure 3 is an example of the relative efficiency gains of a Pelton

unit. Regardless of whether performance has degraded or not, newer turbine designs are

usually more efficient than those designed 30 to 40 years ago. Also, a new turbine can be

designed using actual historical data rather than original design data providing a turbine more

accurately suited for the site.

Newer ―state of the art‖ turbine designs can not only achieve the PPL but also provide

decreased cavitation damage based on better hydraulic design and materials.


Rev. 1.0, 12/06/2011 133

Figure 3: Example - Original vs. New Performance Curves [7]



All Pelton turbine arrangements, vertical or horizontal, have four major components that are

critical to performance losses.

The Runner: There are losses due to friction and turbulence by surface deterioration

and subsequent hydraulic bucket geometry changes.

The Housing/Discharge chamber: There are losses due to case splashing, air

ventilation and tail-water interference.

The Needle Valves/Nozzles: There are losses due to unbalanced velocity profiles and

turbulent fluctuation causing ―bad jet quality‖ (in the form of jet deviation or jet

dispersion).

The Distributor/Manifold: There are losses due to friction, bends and bifurcations (the

split of water into two streams) [5].

The typical losses in a Pelton turbine are approximately as follows:

Inlet pipe (Distributor) and Injector (Nozzle) - 0.5 to 1.0%

Runner - 6.5 to 9.0%

Turbine housing/discharge chamber - 0.5 to 1.0%

A high head multi-jet turbine has relatively lower losses, whereas a low head horizontal unit

has relatively higher losses [3].


Rev. 1.0, 12/06/2011 134

3.1.1Runner

The surface roughness of the runner bucket surfaces must be assessed. There are two

drivers for this surface deterioration; cavitation (Figure 4), and sand/silt erosion (Figure

5). A careful visual inspection can be performed during an outage situation when the unit

is in a dry state.

Figure 4: Cavitation damage on runner bucket [14]

Figure 5: Erosion damage on runner bucket [14]

There is also a possibility of the combined effect of sand/silt erosion and cavitation in the

hydraulic turbine components. It must be noted that properly hydraulic designed Pelton

runners do not cavitate. Yet, even in cavitation-free geometry, surface roughness due to

sand erosion at high velocity regions may initiate cavitation erosion. The synergic effect

of sand erosion and cavitation can be more pronounced than their individual effects.

Bucket erosion has been found to vary with the jet velocity, as compared to water quality

or intake elevation, the jet velocity is the strongest parameter in bucket erosion. As jet

velocity is the function of head, the high head turbines are more vulnerable to silt erosion.

Based on typical qualitative studies it was found that the sharp edge of the splitter

became blunt and the depth of the bucket increased due to sand/silt erosion [14].

The jet loading is also the key to determining the bucket sizing. Most modern runner

designs optimize the ratio of bucket width to jet diameter, which is approximately 3.6 to

4.1, depending on the number of jets and rotational speed. Older machines were often

designed with a lower overall rotational speed and with larger bucket widths compared

with more modern runner designs [7].

An appropriate indicator of efficiency loss due to erosion on a Pelton runner is the width

of the splitter as a percentage of bucket width. A 1 % increase in relative splitter width

represents approximately a 1 % decrease in efficiency [3].


Rev. 1.0, 12/06/2011 135

3.1.2 Housing/Discharge Chamber

Appropriate venting prevents the runner discharge water from building up (in the

housing) [7]. The housing ventilation points need to be assessed to ensure that they are

clear, allowing full ventilation. The tail water levels below the runner must not interfere

with the jet flow. These water levels must remain within the OEM designed range. Jet

interference prevents the regular flow in the buckets and results in the sharp deterioration

of turbine output power with cavitation and vibration [8]. Figures 6 and 7 illustrate the

negative effects of jet interference splash on the turbine performance.

Figure 6: Modeling of jet interference within housing [8]


Rev. 1.0, 12/06/2011 136

Figure 7: Typical Deterioration Due to Jet Disturbance [8]

3.1.3Nozzle

Deterioration assessment of the nozzle is paramount. Needle erosion, as seen in the

examples of Figures 8 and 9, can cause both direct and indirect losses. Direct losses are

the well known losses of friction and turbulence (inner friction), where indirect losses are

caused by bad jet quality, shown in Figure 10 [5].

The purpose of needle and nozzle is to concentrate the jet in a cylindrical and uniform

shape in order to maximize the energy transformation in the runner. Wear on the needle

and nozzle causes a jet deformation which results in decay of efficiency and an

appearance of cavitation.

Figure 8: Eroded Needle

Figure 9: Eroded Needle

0.9

0.95

1

0.7 0.8 0.9 1 1.1

η /

ηo

pt

n11 / n11 opt

Without Jet Disturbance

With Jet Disturbance

at S / Sopt = 2.0

Fig 5. Simulation of Housing Flow [12]


Rev. 1.0, 12/06/2011 137

Figure 10: Photos and sketches of jet quality

Jet visualization is an assessment tool to determine jet deformation. Jet dispersion and jet

deviation can be quantitatively determined from visualization in most cases. Clear

correlation between turbine efficiency and jet quality has been observed. The installation

of equipment for prototype visualization is delicate since the best positioning of camera

and lighting instrumentation cannot be found on the basis of trial and error but must be

based on experience due to the inaccessibility of the equipment.

Furthermore, the mechanical forces of possible water impingement, on the camera and

lighting instrumentation, require a rigid installation (Figure 11). Housings for camera

and lights should be waterproof and measures must be taken to avoid condensation

building up on the lenses. In order to achieve acceptable image quality under the adverse

circumstances present in the housing of an operating Pelton turbine, special equipment is

necessary. The camera housing and the stroboscopic lights were mounted within

protecting housings in the shelter of the injector and cut-in deflector and could be

adjusted at different distances from the nozzle exit with a stepping motor [6].


Rev. 1.0, 12/06/2011 138

Figure 11: Internal view of bracket with camera supports for visualization

3.1.4 Distributor/Manifold

Depending on the age of the turbine unit and original hydraulic design, the distributor

size may contribute to losses and turbulence. A good rule of thumb is to size the unit so

that at full load, the spiral velocity head is 10 % or less of the total unit‘s velocity head.

Older spiral distributors were often constructed in large curved cast sections as compared

with newer units that are usually constructed of shorter mitred ring sections [7].

The ring sections must be assessed routinely for friction increasing internal surface

deterioration. This can take the form of a visual inspection carefully performed during an

outage situation when the unit is in a dry state. For examples of distributor arrangements

see Figures 12 and 13.


Rev. 1.0, 12/06/2011 139

Figure 12: Twin Nozzle distributor arrangement

Figure 13: Multi-Nozzle distributor arrangement

3.2 Operations

Turbine performance is often represented by a graph of turbine efficiency curves versus flow

or output as shown in Figure 14. Also shown are typical turbine performance curves

illustrating the relationship between modern performance, the original design, and a

deteriorated turbine runner (noted as "present performance") [3].

Figure 14: Typical Performance Chart for Pelton Unit [3]

Performance data must be accurately collected. The performance of the turbine can degrade

over time due to cavitation and/or erosion damage and resulting weld repairs. Periodic

performance checks, through absolute or relative (e.g. index) testing, are necessary for

40

50

60

70

80

90

100

40 50 60 70 80 90 100

Turb

ine

Effi

cie

ncy

(%

)

Percent Flow or Output

Modern Performance

Original Performance

Present Performance


Rev. 1.0, 12/06/2011 140

maintaining accuracy, and must be made at a number of operating heads in order to be

comprehensive [3].

Frequent index testing, especially before and after major maintenance activities on a turbine,


controls. Plants should ―as best practice‖ perform periodic performance testing (such as

index testing according to PTC 18 [16]) to assure the most accurate operating curves are

available to optimize plant output. Routinely, this should be done on a 10 year cycle, as a

minimum.

3.3 Maintenance

3.3.1 Weld Repair


performance over time (in default of restorative action) [4]. The usual causes include

cavitation damage, abrasive erosion wear, galvanic corrosion and impact damage from

debris passing through the unit.

Performance-related maintenance techniques involve mainly weld repairs of the turbine

components such as the runner, housing, and distributor tubes. The best practice is to use

a 309L stainless steel welding electrode to return original geometry to runner buckets.

3.3.2Grinding Template

Errors in welding repairs to original bucket profile occur as the unit ages. Original

bucket contour templates should be available at the plant. Trained maintenance personnel

should use these templates to grind and polish the buckets thereby returning them back to

OEM specifications.

3.3.3Surface Coating

After assessment of the water supply quality and historical wear data, it can be evaluated

whether a coating over the natural polished finish of the ASTM A743 [15] stainless steel

(preferred modern erosion and corrosion resistant material) bucket is required. The

results from North American technical papers are inconclusive regarding the benefits for

any hard coating.

3.3.4 Turbine Shaft

Routine turbine shaft maintenance consists of minimizing the corrosion of the shaft

surface with a light coat of oil in the non-water contact areas and periodic re-coating

of areas that come in contact with water with a robust paint such as epoxy. Major

maintenance includes refurbishment on bearing journals, or replace of wearing

sleeve, and re-truing coupling faces during a major unit overhaul.


Rev. 1.0, 12/06/2011 141

3.3.5 Guide Bearings

Turbine guide bearings are usually oil lubricated hydrodynamic bearings.

Maintenance of an oil lubricated bearing and its reliability is directly connected to the

quality of the supplied oil used for lubrication and cooling. Any contamination of

the oil either with debris or water will increase the likelihood of a bearing failure. A

best practice is to install a kidney loop filtration system capable of continuously

removing debris and water from the bearing oil supply.

Extreme shaft vibration can cause contact of the turbine runner‘s seal rings resulting

in wear and the possible failure of the seal rings and subsequent major extended unit

outage. Major maintenance requires the refurbishment of the bearings, such as re-

babbitting of an oil bearing.



The fundamental process for a hydro turbine is described by the efficiency equation, which is

defined as the ratio of the power delivered by the turbine to the power of the water passing

through the turbine.








Turbine performance parameters for Pelton units are defined in ASME PTC-18 [16] and IEC

60041 [17], and typically include the following: Generator Output, Turbine Discharge,

Headwater and Tailwater Elevations, Inlet Head, Discharge Head, Gate Position, and Water

Temperature.


generator bearings and thrust bridge displacements (z). Acoustic emission (on the draft tube

access door or liner) may be measured to track relative cavitation noise.

The condition of the Pelton turbine can be monitored by the Condition Indicator (CI) as

defined according to HAP Condition Assessment Manual [11].




(EFOR). These are universally used by the power industry. Many utilities supply data to the


Rev. 1.0, 12/06/2011 142


operating information is used for improving the reliability of electric generating equipment.

It can be used to support equipment reliability and availability analyses and decision-making

by GADS data users.

4.2 Data Analysis

Analysis of test data is defined in ASME PTC-18 [16] and IEC 60041 [17]. Basically, the

analysis to determine unit efficiency and available power output relative to turbine discharge,

head, and determine operating limits based on vibration and acoustic emission measurements

(CPL). The results will be compared to previous or original unit test data (IPL), and

determine efficiency, capacity, annual energy, and revenue loss. The results will also be

compared to new unit design data (from turbine manufacturer), and determine potential

efficiency, capacity, annual energy, and revenue gain (PPL). For the latter, calculate the

installation/rehabilitation cost and internal rate of return to determine upgrade justification.

Separately, determine the justification of draft tube profile modification using turbine

manufacturer‘s data.




The condition assessment of a Pelton turbine is quantified through the CI as derived

according to HAP Condition Assessment Manual [11]. The overall CI is a composite of the

CI derived from each component of the turbine. This methodology can be applied

periodically to derive a CI snapshot of the current turbine condition such that it can be

monitored over time and studied to determine condition trends that can impact performance

and reliability.







Generation Control), but if not, hard copies of the curves and limits should be made available

to all involved personnel – particularly unit operators, their importance to be emphasized,

and their ability to be understood and confirmed.

Justified projects (hydraulic profiling, unit upgrade), and a method to constantly monitor unit

performance should be implemented.





Rev. 1.0, 12/06/2011 143

The improvement of any hydraulic machinery performance can basically come from three

types of intervention:

Replacement of obsolete runner (the profiled machinery parts) with new ones

Replacement/Improvement of nozzles with new nozzle components

Repair for surface restoration and for improvement of wear resistance.

It is clear that these interventions are not alternative but complementary, depending on the

actual problems of hydraulic design obsolescence of turbine parts and corrosion, erosion, or

cavitation of turbine parts.[10]

Runner Replacement

The modeling of the modern Pelton turbine runner geometry can be carried out with

Computational Fluid Dynamics (CFD) analysis of the jet/bucket interaction. For Pelton

runners, both the flow field itself and the influence of water on the structural properties are

more difficult to determine than for Francis or Kaplan turbines because Pelton buckets are

moving through the jets, filling and emptying continuously. The bucket unsteady loading

analysis requires knowing the unsteady pressure loading in the rotating buckets [9].

Figure 15: Typical results for new runner upgrade [13]

Needle Seat Enlargement

A detailed study showed that the turbine jets could be easily enlarged up to 6 % in diameter

with minor negative effects on efficiency but with a substantial increase in output. This

study details a six-jet Pelton unit with rated head of 675.7 m and an output of 75.2 MW at a

rated jet of 152 mm diameter with a discharge of 12.6 m3/s. The new rated power capacity


Rev. 1.0, 12/06/2011 144

is 87.6 MW with an enlarged jet of 160 mm diameter. Most manufacturers size the needle

seat to accommodate some nozzle machining for maintenance. Normally this will not

significantly affect the contact sealing or interface relationship at small needle opening [7].

Figure 16 shows the typical components that make up a nozzle assembly including the

needle seat.

Figure 16: Typical modern nozzle assembly


Baseline Knowledge:

TERI, The Energy Resources Institute: Electro-Mechanical Equipment – Selection, Best

Practice and use of Checklists - August 2010

ASME Hydro Power Technical Committee: The Guide to Hydropower Mechanical Design -

1996


Palo Alto, CA: 2000. TR-112350-V2.

EPRI, Increased efficiency of Hydroelectric Power, EM 2407 – June 1992

State of the Art:

Karakolcu, A., Geppert, L., Marongiu, J. C.: Performance Prediction in Pelton

Rehabilitation Projects – Vienna 2010

Staubli, T., Bissel, C., Leduc, J.: Jet Quality and Pelton Efficiency

Gass, M.E.: Modernization and performance improvements of vertical Pelton turbines –

Hydropower & Dams Issue Two - 1998


Rev. 1.0, 12/06/2011 145

Kubota, T., Kawakami, H.: Observation of Jet interference in 6-Nozzle Pelton Turbine -FUJI

Electric Review 1990

Keck, H., Wolfgang, M., Weiss, T., Sick, M.: Recent Developments in the Dynamic Analysis

of Water Turbines - 2007





Publications, 3rd

Edition 2002

Vesely, J., Varner, M.: A case study of upgrading of 62.5MW Pelton Turbine – 2000

Thapa, B., Chaudhary, P., Dahlhaug, O., Upadhyay, P.: Study of Combined Effect of Sand

Erosion and Cavitation in Hydraulic Turbines -2007

Standards:

ASTM A743: Standard Specification for Castings, Iron-Chromium-Nickel, Corrosion

Resistant for General Application - 2006

ASME PTC 18, Hydraulic Turbines and Pump-Turbines, Performance Test codes - 2011

IEC 60041 Field Acceptance Tests to Determine the Hydraulic Performance of Hydraulic

Turbines, Storage Pumps and Pump-Turbines, 1991






Lubrication System

Revision 1.0, 12/20/2011

HAP – Best Practice Catalog – Lubrication System

Rev. 1.0, 12/20/2011 147



1.1.1 Lubrication System Components.............................................................................. 148


1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ............................. 150

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ............................ 150





3.0 Operation & Maintenance Practices ................................................................................ 154


3.2 Operations .................................................................................................................... 156

3.3 Maintenance ................................................................................................................. 159



4.2 Analysis of Data ........................................................................................................... 161


5.0 Information Sources: ........................................................................................................ 164


Rev. 1.0, 12/20/2011 148


This best practice for a lubrication system addresses the technology, condition assessment,


reliability of generating units.

The primary purpose of the oil lubrication system is to supply clean oil with appropriate

temperature and pressure to the bearings of the turbine-generator during operation. It is also a

key reliability system for the other machinery under the Power Train Equipment.


Hydropower Facility → Powerhouse → Power Train Equipment → Balance of

Plant/Auxiliary Components → Lubrication System

1.1.1Lubrication System Components

Bearing lubrication systems are critical to unit operation. There are a number of different

types of lubrication system (Pressure, Gravity, and Submersion). The reliability related

components of lubrication systems include the lubricant/oil, filter sub-system, cooling

sub-system, oil pumps, vessel and piping, console/skid and instrumentation/alarm. [1]

Figure 1 illustrates a typical lubrication system console.

Figure 3: Typical Modular Oil Console Arrangement [3]

Twin Oil Cooler/

Heat Exchanger

Twin Oil Filters

Piping

Oil Vessel/Sight Glass

Filtering Sub-System

Transfer Valve

Pressure

control valve


Rev. 1.0, 12/20/2011 149

Lubricant/Oil: The functions of the lubricant/oil are:

1. Minimize friction and wear in Hydro machinery

2. Maintain internal cleanliness by suspending contaminants or keeping

contaminants from adhering to components.

3. Cool moving elements, absorb heat from the contact surface area and transport it

to a location in which it can be safely dissipated.

4. Dampen shock; cushion the blow of mechanical shock. A lubricant film can

absorb and disperse these energy spikes over a broader contact area.

5. Prevent corrosion or minimize internal component corrosion. This can be

accomplished either by chemically neutralizing the corrosive products or by

setting up a barrier between the components and the corrosive material.

6. Transfer energy - A lubricant may be required to act as an energy transfer median

as in the case of hydraulic equipment

Filter Sub-System: The function of the filter sub-system is to continuously provide clean

auxiliary fluid (oil) to the critical equipment. A typical filtration specification for

auxiliary system is 10 absolute particle size, that is, the greatest size of any solid particle

in the oil film should be 10 micron. There are two types of filtration systems; “inline” and

“offline” filtration. The inline filter sub-system consists of a transfer valve (allow transfer

from one bank of components to the stand-by bank of components without significant

pressure pulsations being introduced into the system), filters, differential pressure

indication and alarm. Offline filtration, often call Kidney Loop filtration, functions

independently of the designed lubrication system of the unit.

Cooling Sub-System: The function of this sub-system is to continuously provide cool

auxiliary fluid (oil) at the required temperature to the critical equipment. Most coolers in

use in hydropower plants are of a shell and tube heat exchange design as cooling water is

readily available. As with filter sub-systems, they consist of a transfer valve (allow

transfer from one bank of components to the stand-by bank of components without

significant pressure pulsations being introduced into the system), as well as twin heat

exchangers and a temperature transmitter and alarm.

Oil Pumps: The function of the oil pumps are to continuously supply the system fluid at

the required flow rate. This means it must be capable of interrupted operation for the

same period as the turbine it is servicing.

Vessel and Piping: The vessel functions as the oil reservoir for the system. The correct

sizing is critical for the hydro equipment that the lubrication system is servicing. Size will

be a function of system flow and subsequently the amount of flow the hydro equipment

(main guide bearings, thrust bearings) will actually pass. The function of the piping is to


Rev. 1.0, 12/20/2011 150

connect the console/skid auxiliary equipment (pumps, vessel, etc.) to the Hydro units it

services. The typical oil velocities are in the order of 4 to 6 feet per second.

Console/Skid: The function of the console/skid is to house most of the Lubrication

System components (pumps, vessel, etc.). Since auxiliary equipment must be maintained

and calibrated during operation, it is important for the console/skid to be sized with

ample space for maintenance personal.

Instrumentation/Alarms: The function of the instrumentation is to measure and regulate

the process variables of the auxiliary fluid (oil) such as flow, temperature, level and

pressure. Pressure indicators, temperature indicators, and differential pressure

transmitters are examples of key instrumentation.



There are no best practices directly associated with the unit efficiency and capacity.


Maintain clean, dry oil by periodic analysis of oil condition and regular

sampling for visual and laboratory examination.

Monitor oil filter change time interval (when the filter differential pressure

alarm is activated) to clean oil tank and rundown tanks. This will involve

maintaining operating and temperature records of hydro plant oil system.

Stainless steel reservoir, vessels and piping can be used to ensure minimum oil

flushing time, optimum machinery component life and unit reliability.

High pressure lubrication system can be used on thrust bearings to reduce

friction during start-up and shut down.

System pumps having mechanical seals are recommended instead of shaft

packing.

Follow correct oil flushing procedures will produce an oil system that does not

require frequent on-line filter changeover.

The use of centrifugal pumps eliminates the need for relief and backpressure

(bypass) control valves within the lubrication system.

Monitor turbine vibration. Setting the shaft vibration alarm at 50% of the initial

field value will allow early detection of rotor condition change, and initiate

investigation and an action plan for corrective action before a rotor or

component failure occurs.


Rev. 1.0, 12/20/2011 151

Ensure continuous venting of the non-operating cooler and filter in cold ambient

applications.

Kidney loop filtration should be installed on turbine guide bearing oil systems to

remove debris and water continuously.

Require a Factory Acceptance Test (FAT) for any new oil consoles to duplicate

field conditions as closely as possible and record response times for transients.

Install sight glasses in the drain lines of positive displacement pump relief valve

to confirm that the relief valve is not passing.

Label oil system piping with colored tape to help personnel to understand

system operation and how to take corrective action quickly to prevent unit

damage.



Mechanical – Francis Turbine Best Practice

Mechanical – Kaplan Turbine Best Practice

Mechanical – Pelton Turbine Best Practice

Mechanical – Generator Best Practice




Early designs for oil lubricating systems, for vertical hydro turbine-generator bearings,

consisted of pumps driven by gears or belts from the main shaft or by simple viscosity pumps

which move oil by hydrodynamic action. Horizontal hydro turbine-generator bearings were

often lubricated by oil rings riding on top of the shaft. Modern designs have evolved into

systems which move the oil by electric motor driven pumps. This has many advantages

such as providing electrical controls, backup pumps (AC and DC), and flexible capacities

such as flow rates and pressures.


There are number of designs for Lubrication Sub-Systems that have become state of the art

technology. Lube and seal oil overhead tanks that are not stainless steel will reduce bearing,

oil seal and/or driver control and protection Mean Time before Failure (MTBF), since there

cannot be a filter between these tanks and these components. This is due to iron sulfide

building up in the small clearances of the unit components, which has resulted in premature


Rev. 1.0, 12/20/2011 152

failure. Stainless steel reservoir, vessels and piping can be used to ensure minimum oil

flushing time, optimum unit component life and unit reliability. If oil flushing times can be

reduced, or delayed all together, plant outage times can be significantly reduced.

Replacement of existing non-stainless steel oil system piping, components or the entire

system can usually be justified in un-spared critical equipment.

The most common cause of oil system induced unit trips is the malfunction of relief valves

and/or backpressure control. This can cause an unscheduled shutdown of unit. The use of

centrifugal pumps (Figure 2) eliminates the need for relief and backpressure (bypass) control

valves. Single stage centrifugal pumps can be used whenever the ambient temperature along

with the use of thermostatically controlled reservoir heaters maintain an oil viscosity that

allows the use of a centrifugal pump (oil viscosity is low enough to minimize the effect of

viscosity on centrifugal pump power – low viscosity correction factors).

Figure 4: Centrifugal pump operation [3]

Centrifugal pumps cannot be used when high oil viscosities (>400 centiStokes) are required.

In those applications a positive displacement pump must be used. The function of all pumps

in auxiliary system service is to continuously supply the system fluid at the required pressure

and flow rate. In order to ensure reliable, trouble free operation, pump mechanical seals are

recommended instead of shaft packing. A properly selected and installed pump mechanical

seal in auxiliary system service can operate continuously for a three year period. Function

definition will be met: ‗to supply the system fluid at the required pressure and flow rate‘.

The thrust bearing high pressure lubrication system provides high pressure oil between the

thrust shoes and the runner to provide lubrication on start-up and shut-down of a unit. The oil

is pumped from the bearing oil pot by a high pressure pump, through a manifold to a port

machined in each of the shoes. Figure 3 shows a typical oil ring on a thrust shoe for a high

pressure lubrication system. The primary use for the high pressure lubrication system is to


Rev. 1.0, 12/20/2011 153

reduce friction during start-up and shut down, but it is also a very useful system during

alignment. With the system on, it is possible for a couple of people to rotate a unit by hand or

move the rotating components laterally on the thrust bearing [2].

Figure 5: Lubrication Ports on Thrust Bearing [2]

Supplementary oil cleaning can be achieved by a separate system (Kidney Loop Oil

Filtration System) in series with the existing lubrication system. (Figure 4)

Figure 6: Kidney Loop Oil Filtration

System [L&S Electric, Inc.]


Rev. 1.0, 12/20/2011 154

This system can reduces failures caused by dirty oil thus increased life and performance

of pumps, valves, servos, oil heads and other various hydraulic mechanisms. It can

promote extended oil life and help eliminate moisture in oil.

3.0 Operation & Maintenance Practices


Samples of oil or any deposits need to be taken at regular intervals for visual examination

and laboratory analysis. Best practice includes daily visual examinations, monthly laboratory

examinations for general system and oil conditions, and six-month laboratory examinations

for a more in-depth determination of future oil life. By doing this, detection can be made at

the start of deterioration, contamination or other troubles early and corrective action can be

taken [4]. Figure 5 illustrates the oil film and the testing involved.

Lubricant/oil condition assessment testing [5]:

Viscosity ASTM D445

RPVOT (Rotary Pressure Vessel Oxidation Test) ASTM D2272

Water Content ASTM D1744

Acid Number ASTM D664, ASTM D974

ISO Cleanliness ISO 4406

Rust ASTM D665

Water Separability (Demulsibility) ASTM D1401

Foam ASTM D892

ICP Metals ASTM D6130


Rev. 1.0, 12/20/2011 155

Figure 7: Testing for lubricant degradation in a Turbine Oil System [5]

Another condition assessment activity may involve the replacement an old lubrication system

within a hydro modernization project where assessing newly purchased lubrication consoles

is important for the long term success of the plant. It is a best practice to require a Factory

Acceptance Test (FAT) for the oil console to duplicate field conditions as closely as possible

and record response times for transients (main pump trip and two pump operation) to ensure

optimum oil system field reliability.

As a minimum, the following items should be included in the FAT:

Auto start of the auxiliary pump

Two pump operation

Relief valve checks

Bypass (backpressure) valve proper valve position and stability

Transfer valve operation

Cooler tube leak check

Filter pressure drop and particle check for bypassing

Accumulator pre-charge and bladder condition (if applicable)

Supply valve(s) – proper valve position and stability

Proper supply flow, pressure and temperature

Failure to completely check all oil system component functions during the FAT will result in

delayed start-up and possible lower than anticipated unit reliability for the life of the process


Rev. 1.0, 12/20/2011 156

unit. Chart recorder data for all transient checks (pump trip and two pump operation) and

transfer valve check, are required to be supplied for confirmation that oil supply pressure

during the transient event does not fall to the trip setting.

3.2 Operations

All gravity drain oil systems accumulate debris (oil sludge, etc.) in the oil reservoir over

time. Increasing frequency of oil filter change (significant increase – say from once per year

to once every six months) indicates a need to clean the oil reservoir and rundown tanks at the

next turnaround. It is a best practice to monitor oil filter change time (when the filter

differential pressure alarm is activated) to clean oil tank and rundown tanks. This is a

predictive approach that will minimize oil reservoir and overhead tank cleaning cycles while

still ensuring unit reliability. Every time the unit is shut down, any oil contained in the tank

and all associated debris enters the seal without the benefit of filtration. Therefore, attention

should be given to any overhead seal oil tanks that have never been cleaned, but are exposed

to the process gas and associated process debris.

In cold climates (ambient temperatures below 15° C at any time of the year), cool, static oil

in the non-operating cooler and filter will cause a transient pressure drop when it is comes

on-line. Low oil pressure alarms will occur for critical equipment (e.g., when auxiliary pump

does not start or does not start in time). It is a best practice to continuously vent the non-

operating cooler and filter in cold ambient applications. An enable reliable operational

transfer (cooler or filter) always maintains this non-operating equipment with open

ventilation and at the same temperature as the operating equipment. Where an alarms/trip has

been caused by the issue noted above, operating procedure should be revised and orificed

vents installed if required.

Since only the oil film keeps gear and screw components from contacting each other, a

plugged main pump suction strainer will rapidly increase pump clearance and cause the

auxiliary pump to start. It is a best practice to install differential pressure transmitters to

alarm on high differential pressure, for control room monitoring, around pump suction

strainers – especially screw and gear pumps. The source of the main pump strainer blockage

will eventually plug the auxiliary strainer and result in auxiliary pump damage.

It is very difficult to confirm that a positive displacement pump relief valve is not passing. A

friction-bound relief valve can cause an unexpected shutdown of an oil system by passing an

additional amount of oil that can force the start-up of an auxiliary pump, thus exposing the

unit to a shutdown if the auxiliary pump does not start in time. It is a best practice to install

sight glasses in the drain lines of positive displacement pump relief valve to confirm that the

relief valve is not passing.


Rev. 1.0, 12/20/2011 157

Figure 8: Sight glasses in the drain lines [Maritime Park Association]

Most oil system relief valves are the modulating type with a small bypass hole to prevent

sticking of the valve. This allows a small continuous flow to pass through the valve. Feeling

the discharge line of the relief valve gives a false impression of valve condition. Using a

sight glasses is a correct way to confirm the proper operation of relief valves.

Regarding the control aspects of the system, it is best practice that existing lubrication

systems be modified to be Triple Modular Redundant (TMR) if any trip system un-scheduled

shutdowns have occurred. Oil systems without TMR shutdown logic experience lower

reliability than TMR systems and corresponding lower serviced unit reliability. TMR

shutdown functions for two-out-of-three voting will positively eliminate shutdown

instrumentation related failures and prevent spurious shutdowns. Require TMR transmitters

for all shutdown functions in new project work or field modifications, to maximize serviced

unit reliability.

Similarly, oil systems installed as late as the 1980s use single switches for pressure and

temperature protection of machine components. These old devices expose the plant to

unscheduled shutdowns. It is a best practice to replace mature plant switches with TMR

transmitters in all trip circuits for optimum oil console and serviced unit reliability.

TMR smart transmitters (two-out-of-three voting for a trip) ensure accurate and reliable

operation, and prevent spurious trips. Many plants have registered low machine reliability

and corresponding revenue losses because of the malfunctioning of old instrumentation.

Considering forced outages, it is easy to justify the installation of TMR smart transmitters for

all trip circuits in critical equipment installations.

Failure to mark and monitor control valve stem position in oil systems has led to many

surprises and replacements soon after a turnaround. It is a best practice to monitor control


Rev. 1.0, 12/20/2011 158

valve stem position to identified worn components and allowed replacement during an

outage. By monitoring the control valve position (see Figure 6), a determination of

components wear (rotary pumps, bearings and seals) will ensure corrective action is taken

during an outage. Marking the position of control valves (marking the stem and valve yoke

with a straight edge) at the beginning of a run will give an instant indication of component

wear for the following items:

Rotary pumps (screw or gear) – if the bypass valve is closing over time.

Bearing wear – if the lube oil supply valve is opening over time.

Control component wear – if the control oil supply valve is opening over time.

Seal wear – if the seal oil supply valve is opening over time.

Figure 9: Typical collection of data from the control valve assembly

Check the position of all marked control valves prior to the turnaround meeting to determine

if the affected components need replacement during the turnaround. Remember that

turnaround action does not affect product revenue, but unplanned action does! Replacement

of an oil pump can take two days considering alignment. Replacement of a bearing or seal

can take three to five days.

Using colored tape or paint to define each individual line of the system (supply lines, return

lines, bypass lines) promotes ownership and personnel awareness on site thus increasing

system safety and reliability. It is a best practice to label oil system piping with colored tape

to help personnel to understand system operation and how to take corrective action quickly to

prevent unit trips. Figure 7 shows examples of piping labels. Many critical machine unit


Rev. 1.0, 12/20/2011 159

shutdowns are the result of not monitoring the local instrument and components in the

system. Failure to properly label piping, instruments and components leads to neglect and

corresponding low oil system reliability.

Figure 10: Typical Piping Labels

3.3 Maintenance

Maintenance of an oil lubricated bearing and its reliability is directly connected to the

quality of the supplied oil used for lubrication and cooling. Any contamination of the oil

either with debris or water will increase the likelihood of a bearing failure.

Oil filters are usually positioned downstream of the oil coolers to prevent carbon steel (iron

sulfide) particles from entering the machinery components and causing pre-mature

wear/failure. Shell and tube oil coolers typically have the water in the tubes and oil in the

shell and are made of carbon steel for cost reasons. It is a best practice to use of stainless

steel coolers and filters. This can easily be justified and will ensure maximum life of

machine components.

Lubrication system flushing may be either a displacement flush after a drain and fill, or a

high velocity flush for initial turbine oil fills. A displacement flush is performed concurrently

during turbine oil replacement, and a high velocity flush is designed to remove contaminants

entering from transport and commissioning of a new turbine. Displacement flushes, using

separate flush oil, are to remove residual oil oxidation product that cannot be removed by

draining or vacuum. A displacement flush is conducted by utilizing lubrication system

circulation pumps without any modification to normal oil circulation flow paths, except for

potential kidney loop filtration. This flush is typically done based on a time interval vs.


Rev. 1.0, 12/20/2011 160

cleanliness (particle levels) to facilitate the removal of soluble and insoluble contaminants

that would not typically be removed by system filters.

Best practices in high-velocity flushing are as follows:

Supply and storage tanks should be clean, dry and odor-free. Diesel flushing is not

acceptable.

Two to three times’ normal fluid velocity achieved with external high-volume pumps,

or by sequential segmentation flushing through bearing jumpers.

Removal of oil after flush is completed to inspect and manually clean (lint-free rags)

turbine lube oil system internal surfaces.

High-efficiency bypass system hydraulics to eliminate the risk of fine particle damage

[5].



In standard ASTM D4378-08 [7], an equation was developed for turbine severity, B, is as

follows:

B = M (1 - X/100)/(1 - e-Mt/100

)

Where: B is the turbine severity

M is the fresh oil makeup expressed as the percent of total charge per year

t is the years of oil use

X is the used oil oxidation resistance in the Test Method D 2722 rotary pressure

vessel text expressed as % of fresh oil

In standard ISO 4406, oil cleanliness levels are defined by three numbers divided by slashes

(/). The example below illustrates the use of ISO 4406 code chart.


Rev. 1.0, 12/20/2011 161

Figure 11: ISO 4406 Code Chart [8]

These numbers correspond to 4, 6 and 14 micron. Each number refers to an ISO Range Code,

which determines by the number of particles for that size (4, 6 and 14mm) and larger present

in 1ml of oil.

4.2 Analysis of Data

Analysis of test data is defined in standard ASTM D4378-08.

The analysis of data using the oil cleanliness levels from the ISO 4406, are illustrated below:


Rev. 1.0, 12/20/2011 162

Figure 12: Oil Cleanliness Levels [8]


Rev. 1.0, 12/20/2011 163


Interpretation of test data and recommended actions are defined in ASTM D4378-08.

The integration of the ISO 4406 oil cleanliness levels can be used for the selection and

specification of system characteristics and the equipment that it services.

Figure 13: ISO 4406 Target Level Chart [8]


Rev. 1.0, 12/20/2011 164


Baseline Knowledge:

EPRI, Hydro Life Extension Modernization Guides: Volume 4-5 Auxiliary Mechanical and

Electrical Systems TR-112350-V4 – Palo Alto, CA – 2001

USBR, Alignment of Vertical Shaft Hydro Units, Facilities, Instructions, Standards and

Techniques Volume 2-1 – Colorado - 2000

State of the Art:

Forsthoffer, W., E., Best Practice Handbook for Rotating Machinery – 2011

McKenna, K., P. E., Turbines and Their Lubrication -The Engineered Difference, Spring

2001

Hannon, J., B., How to Select and Service Turbine Oils - Machinery Lubrication, July 2001

ANALYSTS, INC, Vitalpoint Advanced Fluids Assessment - Form 40601208 – 2008

Standards:

ASTM D4304, Standard Specification for Mineral Lubricating Oil used in Steam and Gas

turbines -2006

ISO 4406 Code, HYDAC Innovative Fluid Power: Overview Brochure – 1999


Governor

Revision 1.0, 12/15/2011

HAP – Best Practice Catalog – Governor

Rev. 1.0, 12/15/2011 166

1.0 Scope and Purpose .......................................................................................................... 167


1.1.1 Governor Components ........................................................................................ 167


1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ................... 169

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ................. 169


2.0 Technology Design Summary ......................................................................................... 170



3.0 Operation and Maintenance Practices ............................................................................. 176


3.2 Operations .................................................................................................................... 177

3.3 Maintenance ................................................................................................................. 179

4.0 Metrics, Monitoring and Analysis .................................................................................. 181


4.2 Data Analysis ............................................................................................................... 182


5.0 Information Sources ........................................................................................................ 183


Rev. 1.0, 12/15/2011 167


This best practice for a hydraulic turbine governor addresses the technology, condition

assessment, operations, and maintenance best practices with the objective to maximize

performance and reliability of generating units. The primary purpose of the governor is to control

the turbine servomotors which adjust the flow of water through the turbine regulating unit speed

and power. How the governor is designed, operated, and maintained will directly impact the

reliability of a hydro unit.


Hydropower Facility → Powerhouse → Power Train Equipment → Governor

1.1.1 Governor Components

A governor is a combination of devices that monitor speed deviations in a hydraulic

turbine and converts that speed variation into a change of wicket gate servomotor

position which changes the wicket gate opening. This assembly of devices would be

known as a ―governing system‖. In a hydro plant this system is simply called the

―governor‖ or ―governor equipment‖. For a single regulating turbine (Francis and

Propeller), a governor is used to start a hydro unit, synchronize the unit to the grid, load,

and shut down the unit. For a double regulating turbine (Kaplan), a governor would also

add control to the runner blade servomotor which changes the pitch of the runner blades

to maintain optimal efficiency of the turbine for a given wicket gate opening. This is

usually done through a mechanical cam or digitally through an electronic controller.

Double regulating is also used for dual control of a Pelton‘s nozzle opening and deflector

position. This double regulation establishes an exact relationship between the position of

the needle valve and the deflector to allow the deflector to intercept the jet of water flow

before closure of the needle valve thereby reducing the water hammer effect in the

penstock.

A governor is usually not considered as an efficiency component of a hydro unit, except

for a Kaplan unit‘s double regulation of blade angle versus wicket gate position which is

an important driver for performance and efficiency. For a Kaplan turbine governor, a 2D

or 3D cam (or electronic equal) for blade positioning and the Kaplan feedback/restoring

mechanism, together supply the double regulating function. The details are described as

follows:

Double Regulating Device: The function of the double regulating device for a Kaplan

turbine is to provide a predetermined relationship between the blade tilt angle and the

wicket gate opening. This is done by a 2 dimensional (2D) or a 3 dimensional (3D) cam.

A 2D mechanical cam provides a relationship between blade tilt angle and wicket gate

opening. A 3D cam adds the third dimension of head usually by means of an electronic

or digital controller. A 2D cam has to be manually adjusted for different head ranges

whereas a 3D cam automatically adjusts for head changes.

Kaplan Blade Position Feedback: The restoring mechanism is a ―feedback‖ device that

feeds back the current blade tilt angle and the post movement command position to the


Rev. 1.0, 12/15/2011 168

control system. In a mechanical governor this is typically a pulley cable system, and with

digital governors it may be a linear potentiometer or linear magnetostrictive (non-contact)

electrical positioning system.

The non-performance but reliability related components of a governor include the oil

pressure system, flow distributing valves, control system, Permanent Magnet Generator

(PMG) or speed sensor, control system, wicket gate restoring mechanism, and creep

detector. As a note, many references consider the wicket gate servomotors as part of the

governor system. However for HAP, the servomotors are considered part of the turbines

and are addressed in the turbine best practices.

Oil Pressure System: The oil pressure system consists of oil pump/s, oil accumulator

tank/s, oil sump, and the necessary valves, piping, and filtering required (pressure

tanks/accumulators are not addressed in this best practice document).

Flow Distributing Valves: The distributing valve system varies in design depending on

the type of governor. For a common mechanical governor, the system consists of a

regulating valve (that moves the servomotors) that is controlled by the valve actuator,

which is in turn controlled by the pilot valve. These valves coupled with the oil pressure

system provides power amplification in which small low force movements are amplified

into large high forces movements of the servomotors.

Control System: The control system can be mechanical, analog, or digital depending on

the type of governor. In the truest sense, the control system is the ―governor‖. The

purpose of all other components in a governor system is to carry out the instructions of

the control system (governor). For mechanical governors, the control system consists of

the fly-ball/motor assembly (ball-head or governing head) driven by the PMG, linkages,

compensating dashpot, and speed droop device.

Speed Sensor: Mechanical governors use a permanent magnet generator (PMG) as

rotating speed sensor which is driven directly by the hydro unit. It is basically a multi-

phase PMG that is electrically connected to a matching multi-phase motor (ball head

motor) inside the governor cabinet that drives the fly-ball assembly (or governing head)

which is part of the control system. Analog and Digital governors use a Speed Signal

Generator (SSG) driven directly by the unit which provides a frequency signal

proportional to the unit speed usually through a zero velocity magnetic pickup monitoring

rotating gear teeth or through generator bus frequency measured directly by a Potential

Transformer (PT).

Double Regulating Device for Pelton Turbine: Double regulation for a Pelton turbine

provides for an exact relationship between the position of the needle valve and the

deflector to allow the deflector to intercept the jet of water before closure of the needle

valve thereby reducing any water hammer in the penstock. This is done by a mechanical

connection between the needle valve and deflector.

Wicket Gate Position Feedback: The restoring mechanism is a ―feedback‖ device that

feeds back the current wicket gate position and the post movement command position to

the control system. In a mechanical governor this is typically a pulley cable system, and


Rev. 1.0, 12/15/2011 169

with digital governors it may be a linear potentiometer or linear magnetostrictive (non-

contact) electrical positioning system.

Creep Detector: The creep detector is a device, usually mounted on the PMG or part of

speed sensor that is capable of measuring very slow shaft revolutions. Its purpose is to

detect the beginning of shaft rotation that might occur from leakage of the wicket gates

while the unit is shut down. The system detects movement and turns on auxiliary

equipment, such as bearing oil pumps, to prevent damage.

In addition to the above devices, some auxiliary equipment associated closely with the

governing system and often found in, on, or near the governor cabinet which is not

addressed in this Best Practice, such as: synchronizer, shutdown solenoid, tachometer,

over speed switch, generator brake applicator, governor air compressor, and various

gages and instruments. These can vary greatly in design depending on the type of

governor or turbine.



The governor performance refers to the ability of off-line and on-line responses,

sensitivity to hunting, accuracy of frequency, synchronization time, and the

ability to start remotely. These performances can affect the unit generation

performance directly or indirectly. One best practice is periodic testing to

establish accurate current governor performance characteristics and limits.

Periodic analysis of governor performance at Current Performance Level (CPL)

to detect and mitigate deviations of expected performance from the Installed

Performance Level (IPL) due to degradation or wear.



Maintain documentation of the IPL and update when modifications to equipment

are made.

Index testing of Kaplan turbines following ASME PTC 18-2011 [19], must be

done periodically (10 year cycle minimum) or after major maintenance activities

on the turbine, to establish the best blade angle to the gate opening relationship

and update the 2D or 3D cam.


Digital governors are the state of the art technology for hydro turbine governing

system, use digital type governor for new installation. They can be either

proprietary controllers or controllers based on industrial PLCs.


Rev. 1.0, 12/15/2011 170

Rather than to replace the entire governing system it may be more cost effective

to retain many of the mechanical components (i.e. pumps, accumulator tank,

sump, etc.) and perform a digital upgrade or retrofit.

As a best practice, use a non-contact linear displacement feedback sensor such

as a Magnetostrictive Linear Displacement Transducer (MLDT) rather than a

contact sensor such as a linear potentiometer which will wear over time.

For new governors or retrofits, choose a well known reputable manufacturer that

will be around to support the equipment for long term. Use industry

acknowledged ―up to date‖ choices for governor components materials and

maintenance practices.

Monitor the governor pump cycle time, during regulating and shutdown to

establish a baseline and trend any increases that may be indicative of internal

leakage of the valves or problems with the turbine servomotors. Monitor pump

noise and vibration which can be an indication of bearing failures, excessive oil

foaming, loose pipe connections, and possible blockage of oil flow. Adjust

maintenance and capitalization programs to correct deficiencies.

Oil tests should show oil cleanliness meeting an ISO particle count of 16/13,

viscosity should be within +/-10% of manufacturer‘s recommended viscosity,

metals should be under 100 parts per million (ppm), acid number less than 0.3,

and the moisture content should be less than 0.1%. Oil should be tested as a

minimum every 6 months. Compare and contrast the results to establish trends

for increases in contamination or decrease in lubricant properties.

Only lint-free rags should be used to wipe down the vital parts inside a governor

since the lint can be a source of oil contamination leading to binding of certain

critical control valves.



Mechanical – Lubrication System Best Practice






The four types of governors that have been used for hydraulic turbines throughout history

are: mechanical, mechanical-hydraulic, analog, and digital. The purely mechanical governor


Rev. 1.0, 12/15/2011 171

is for very small applications requiring little motive force in the actuator and was developed

in the late 1800‘s. Amos Woodward received his first governor patent for controlling water

wheels in 1870. A significant improvement occurred in 1911 when Elmer Woodward

perfected the mechanical-hydraulic actuator governor adding power amplification through

hydraulics [3]. One of the first being a gate shaft type governor as shown in Figure 1. These

actuator governors could be applied to very large hydraulic turbines which required large

forces to control the wicket gates. They ultimately evolved into the cabinet actuator governor

as shown in Figure 2. Analog governors, with electronic Proportional-Integral-Derivative

(PID) control functions, which replace the ball-head, dashpot, and linkages, were developed

in the early 1960‘s. Digital governors (PID through software) were developed in the late

1980‘s and have advanced with improvements of micro-processor capabilities. [1]

Figure 3 shows a block diagram for a single regulating mechanical-hydraulic governor and

turbine control system as compared to Figure 4 showing a digital governor. The solid line

blocks are part of the governor controls and the dashed line blocks are part of the turbine

controls.

Figure 1: Gate Shaft Governor

Figure 2: Mechanical Cabinet

Actuator Governor


Rev. 1.0, 12/15/2011 172

Figure 3: Mechanical-Hydraulic Governor (Solid line) and Turbine Control System

(Dashed line) [7]

Figure 4: Digital Governor (Solid line) and Turbine Control System (Dashed line)


Rev. 1.0, 12/15/2011 173

As a best practice, governors being purchased should be specified according to IEEE 125

[15] and/or IEC 61362 [17].

Performance levels for governors can be stated at three levels as follows:

The Installed Performance Level (IPL) is described by the governor performance

characteristics at the time of commissioning. These may be determined from

manufacturer shop reports and records from field commissioning tests.

The Current Performance Level (CPL) is described by an accurate set of governor

performance characteristics determined by field testing.


to governor design information from the manufacturer.


Mechanical cabinet actuator governors (Figures 2 and 5) are the dominate type of governors

in service today for hydro turbines but are no longer manufactured due to their high cost.

Analog governors have more functionality over mechanical governors but still have more

hardware components than a modern digital governor [1]. As a result, digital governors with

their lower cost, and versatility through software programmability, are the governors of

default today for new installations or replacements, as the state of the art technology for

hydro turbine governors. Custom proprietary controllers such as that shown in Figure 8 are

available, as well as systems based on industrial Programmable Logic Controllers (PLCs).

Figure 5: Mechanical-Hydraulic

Governor

Figure 6: Analog Governor


Rev. 1.0, 12/15/2011 174

Figure 7: Proportional Valve - Main

Valve Assembly for Digital Governor

Figure 8: Digital Governor

As a best practice, rather than replace the entire mechanical or analog governing system,

often a cost effective solution is to retain many of the mechanical components (i.e. pumps,

accumulator tank, sump, etc) and perform a digital upgrade or retrofit. This allows the hydro

plant to retain the reliability of some of the existing equipment and also retain the familiarity

with that equipment while reducing the installed cost versus a new governor. The upgrades

usually include installing a digital controller (PLC) and electronic speed sensor to replace the

mechanical components (PMG, ball-head, linkages, dashpot, etc.) and an analog controller.

In addition, a proportional valve usually replaces the pilot valve and an electronic feedback

position sensor replaces mechanical restoring cable. It is possible to add remote

communication features, fast on-line ramp rates, out-of-calibration alarms, a touch screen

human machine interface (HMI), and many other features not possible with legacy governors

[11]. Figure 6 shows an original analog governor and Figures 7 and 8 show the same

governor upgraded to digital controls. Figure 9 shows a PMG and associated mechanical

speed switches with a speed indicator probe and creep detector on top. Figure 10 shows an

electronic speed sensor assembly with zero velocity sensors monitoring a gear.


Rev. 1.0, 12/15/2011 175

Figure 9: Top of PMG

Figure 10: Digital Speed Sensor/s

Figures 11 and 12 show the contrast between a typical wicket gate servomotor mechanical

restoring cable for a mechanical governor feedback versus an electronic MLDT for feedback

to a digital governor. As a best practice, use a non-contact linear displacement feedback

sensor such as a MLDT rather than a contact sensor such as a linear potentiometer which will

wear over time.

Figure 11: Restoring Cable – Mechanical

Feedback

Figure 12: MLDT Electronic

Feedback

As a general cautionary note, one should be aware that the product life cycle of digital

governors is relatively short, as with most computerized technology of today. Therefore,

over time, spare parts can become difficult to procure. The software and the hardware

running it can be obsolete in as little as 10 years [11]. A best practice would be to choose a

well known reputable manufacturer that will be around to support the equipment for long

term. Use industry acknowledged ―up to date‖ choices for governor components materials

and maintenance practices.


Rev. 1.0, 12/15/2011 176



After the commercial operation begins, how the governor is operated and maintained will

have a major impact on loss prevention of the IPL and CPL and maintaining the unit

reliability. An unforeseen failure of the governor can have a substantial impact on revenues

due to the extended forced outage. Therefore, it is important to maintain a current

assessment of the condition of the governor and plan accordingly. A condition assessment of

a governor system would include the evaluation of the age of the equipment, operating and

maintenance history, availability of spare parts, and performance [10].

Using the age of any equipment to assess the condition is very subjective, since how the

equipment is operated and maintained over its life will directly affect the wear of its

components. However, age is still an important measure of wear of mechanical parts. Just as

with electronic parts, as the components age, they may deteriorate from exposure to heat,

vibration, and contamination of dirt and oil [10].

Mechanical-hydraulic governors (Figures 1, 2, and 5) are usually very reliable, with the most

common problems being oil leakage (external and internal), sticking valves, looseness in pins

and linkages due to wear, and misadjustments. Some leakage is acceptable and provisions

are usually made by the manufacturer for normal leakage. A condition assessment would

include observation of the leakage and discussion with the hydro plant maintenance

technicians as to the amount of daily or weekly maintenance required and of any major past

repairs. A sign of excessive external oil leakage is usually evident from the observation of

extreme use of oil absorbent materials, rags, and catch containers in the governor cabinet.

This external oil leakage drains back to the sump bringing with it any dust and dirt that enters

the cabinet resulting in contamination of the oil.

A sign of excessive internal oil leakage is a frequent cycle time of the governor oil pump.

IEEE 125 [15] and Goncharov [9] recommend that the oil pressure system (pump/s and

accumulator/s) should be designed such that the minimum pump cycle is 10 minutes while

the governor is controlling steady state. This value factors in internal leakage and the

regulating use of the oil. However, even with minimal internal leakage, the pump cycle time

will vary greatly depending on whether the unit is shutdown, starting up, regulating (isolated

mode will require more than when connected to a stable grid), or shutting down since the

amounts of oil use are different at all these different circumstances. For example, the pump

may not cycle for 30 minutes, an hour, or longer while the unit is shut down, but may operate

continuously while the unit is starting up or shutting down. In any case, the pump/s should

be rated for the service that they actually see in service. Some very large governors use a

small ―jockey pump‖ which is designed to operate continuously while the unit is operating

steady state. So this pump would be rated for continuous service. As a best practice, one

should monitor the pump cycle time of the plant governors, during regulating and shutdown

to establish a baseline and trend increases that may be indicative of internal leakage of the

valves or problems with the turbine servomotors. This also allows such trending of pump

cycles to be used to compare the governor condition of similar units. Also, one should


Rev. 1.0, 12/15/2011 177

monitor pump noise and vibration which can be an indication of bearing failures, excessive

oil foaming, loose pipe connections, and possible blockage of oil flow [12].

The importance of clean oil cannot be understated, so any condition assessment would

analyze oil test reports to ensure the oil suspended particulate is low and moisture content is

low. Excessive metal particulate is a sign of major wear of valve internals (pilot, valve

actuator, proportional, or distributor) and should be addressed as soon as possible. As a best

practice, results from oil tests should show oil cleanliness meeting an ISO 4406 particle

count of 16/13, viscosity should be within +/-10% of manufacturer‘s recommended viscosity,

metals should be under 100 parts per million (ppm), acid number less than 0.3, and the

moisture content should be less than 0.1%. Oil should be tested as a minimum every 6

months.

Analog and digital governors (Figures 6, 7, and 8) have mechanical components so they

share many of the same maintenance requirements as a mechanical-hydraulic governor. A

condition assessment would include the same approach, as stated above, with the mechanical

inspection generally limited to the hydraulic governor head assembly, which consists of the

proportional valve and associated control components [10]. Electronic components should

be inspected for any signs of looseness in connections, overheating, and any contamination

of dirt or oil on the components. Overheating of the oil in the sump, from an extended unit

operation or excessive internal leakage in the system, can cause the release of oil vapors into

the governor cabinet which will condense on the cooler surfaces. Also, oil leakage will

increase with oil temperature. This oil vapor condensation can cause major problems with

electronic components if they happen to be located within the cabinet.

Any condition assessment should also include an inventory of spare parts. All necessary

mechanical and electronic parts required to keep the governor operational should be available

in plant inventory, or on short notice depending on the criticality of the unit to the system.

The measured performance of a governor is a major indicator for the condition assessment.

Performance measures should include off-line and on-line response, sensitivity to hunting,

accuracy of frequency, synchronization time, and the ability to start remotely. ASME

Performance Test Code, PTC 29 [14] provides the rules and procedures for executing

governor performance tests.

3.2 Operations

Mechanical-hydraulic governor for a hydraulic turbine is a simple and reliable device for

controlling speed and power output. Stabilization of the unit is provided by a compensating

dashpot while the same function is provided electronically or digitally in an analog or digital

governor. Governor dead time is defined as the elapsed time from the initial speed change to

the first movement of the wicket gates for a rapid change of more than 10 percent of load.

The dead time for a mechanical-hydraulic governor is 0.25 seconds whereas the dead time

for an analog or digital governor is less than 0.2 seconds which enables to governor to

provide accurate stable speed control [2]. Through the operation of a governor a unit is

started up, synchronized to the grid, loaded, and then shut down. Also, its function is

coordinated with the operation of various other types of auxiliary equipment in the unit such


Rev. 1.0, 12/15/2011 178

as lubrication pumps, cooling water pumps, excitation control, brakes, protective relays, and

the main generator breaker.

Kaplan turbines are double regulated such that as the wicket gates move the blades tilt to

follow a pre-established relationship with wicket gate position and head. This is usually

done in a mechanical governor via a 2D cam as shown in Figure 13. More advanced

governors with 3D cams (electronic equal), as shown in Figures 14, 15, and 16, monitor head

and continually update that relationship via software. As the turbine condition degrades, the

efficiency reduces and subsequently the mechanical 2D cam surface may wear [8].

Therefore, as a best practice, index testing following ASME PTC 18-2011 [19], must be done

periodically (10 year cycle minimum) or after major maintenance activities on the turbine, to

establish the best blade angle to the gate opening relationship and update the 2D or 3D cam.

An example of the changing of that relationship and setting of a new curve is shown in

Figure 1 of the Propeller / Kaplan Best Practice document.

Figure 143: 2D Mechanical Cam Figure 14: Kaplan Blade Position –

Electronic - MLDT


Rev. 1.0, 12/15/2011 179

3.3 Maintenance

This Best Practice document does not replace the manufacturer‘s maintenance manual for

servicing the governor. Governor maintenance and adjustments should be performed

following the manufacturer‘s guidelines. A good thirty-party reference for mechanical-

hydraulic governor maintenance is the USBR‘s Mechanical Governors for Hydroelectric

Units [5].

Many hydro plants still prefer a mechanical-hydraulic governor over a modern digital

governor. Even though mechanical-hydraulic governors are no longer manufactured, parts

can be reversed engineered or procured from third-party manufacturers. The part technology

is static, reliability is proven, and maintenance cost is generally low and established. Also,

Figure 16: 3D Digital Cam Blade Oil Head

Figure 15: 3D Digital Cam for Blade


Rev. 1.0, 12/15/2011 180

the maintenance personnel are familiar with the equipment and are trained to maintain and

repair the equipment [1]. However, time and associated wear takes a toll on almost all

devices including governing equipment. Electrical and mechanical parts will wear to a point

that they have to be replaced. At times, repair parts may be too expensive, obsolete, or not

available so the governor has to be replaced or upgraded with new one, which is usually

digital [6].

Clean oil is the lifeblood of a hydraulic actuated governor. Sticking valves, whether they are

pilot valves or distributor valves of a mechanical governor or proportioning valves in a

digital governor is a common symptom of dirty oil. Reconditioning of the oil by routine

centrifuging and filtering during routine outages is recommended. As a best practice, many

plants connect a kidney loop filtration system to the governor sump to continuously filter the

oil, as shown in Figure 17. Such filtration systems are capable of removing particulate and

also can remove moisture if designed accordingly.

Figure 17: Kidney Loop Filtration on Sump

Mechanical-hydraulic governors contain sets of delicate and intricate linkages and valves in

which if any single component fails it may cause the entire system to malfunction. As a best

practice, it is very important to keep the components free from accumulation of dirt and dust

and keep the linkages and bearing adequately lubricated with oil [7]. Binding in the linkages

and bearings due to lack of lubrication or dirt buildup is a frequent cause of governor trouble.

As a best practice, only lint-free rags should be used to wipe down the vital parts since the

lint can be a source of oil contamination leading to binding of certain critical control valves.

[4].

Analog and digital governor systems have mechanical components that have to be

maintained just like mechanical-hydraulic governors. It addition, they have common

maintenance problems such as loose wire and card connections that may vibrate free


Rev. 1.0, 12/15/2011 181

over time. Any maintenance program, as best practice, must include checking and

tightening these components periodically to avoid the otherwise resulting unit trips and

forced outages. Electronic components do fail from time to time, so it is imperative to

have adequate spare parts on site and the maintenance personnel properly trained to

troubleshoot and repair the governor.

If the decision is to retain a satisfactorily operating mechanical-hydraulic governor which is

in good condition, there are other maintenance related upgrades and retrofits that can be

made to the equipment to provide even higher reliability, such as: electronic 3D cams (for

Kaplan blade actuation, see section 3.2), pump un-loader pilot valve kit and oil strainer

(Figure 18), electronic speed switch kits, and improved pilot valve strainers (Figure 19).

Figure 18: Pump Un-Loader Pilot Valve &

Strainer

Figure 19: Pilot Valve Duplex Strainer



The fundamental performance for a governor is described by the quality of its speed

regulation of a hydraulic turbine. This quality can be determined by its performance

measures.

The measured performance of a governor is a major indicator for the condition assessment.

ASME PTC-29 [14] specifies procedures for conducting tests to determine the following

performance characteristics of hydraulic turbine speed governors:

Droop - permanent and temporary


Rev. 1.0, 12/15/2011 182

Deadband and Deadtime – speed, position, and power

Stability index - governing speedband and governing powerband

Step response

Gain (PID) - proportional gain, integral gain, and derivative gain

Setpoint adjustment - range of adjustment and ramp rate

A similar international code is IEC 60300 [16].

Index testing of Kaplan turbines following ASME PTC 18-2011 [19], must be done

periodically (10 year cycle minimum) or after major maintenance activities on the turbine, to

establish the best blade angle to the gate opening relationship.

The condition of the governor can be monitored by the Condition Indicator (CI) as defined

according to HAP Condition Assessment Manual [13].



indicators, such Equivalent Availability Factor (EAF), Equivalent Forced Outage Factor

(EFOR), and event reports. Many utilities supply data to the Generating Availability Data

System (GADS) maintained by NERC. This database of operating information is used for

improving the performance of electric generating equipment. It can be used to support

equipment reliability and availability analysis and decision-making by GADS data users.

4.2 Data Analysis

Analysis of test data is defined in ASME PTC-29 [14] and/or IEC 60300 [16]. Basically,

determine current performance measurements (CPL). Compare results to previous or

original governor test data (IPL), and determine any reduction in performance. Compare

results to new governor design data (from governor manufacturer), and determine potential

performance (PPL). For the latter, calculate the installation/rehabilitation cost and internal

rate of return to determine upgrade justification.

Analyze index test results performed on Kaplan unit to determine if a new 2D or 3D cam (or

electronic equal) must be updated.

Monitor the governor pump cycle timeduring regulating and off line to establish a baseline,

and trend any increases that may be indicative of internal leakage of the valves or problems

with the turbine servomotors.

Monitor the condition of the oil through periodic testing, compare the results to establish

trends for any increase in contamination or decrease in lubrication properties.

The condition assessment of a governor is quantified through the CI as derived according to

HAP Condition Assessment Manual. The overall governor CI is a composite of the CI

derived from each component of the governor. This methodology can be applied periodically


Rev. 1.0, 12/15/2011 183

to derive a CI snapshot of the current governor condition such that it can be monitored over

time and studied to determine condition trends that can impact performance and reliability.



Performance Indexes and Equations [18]. Event reports can be analyzed for outages or

deratings by equipment cause codes to ascertain the impact of governor related events

(governor cause codes 7050 and 7053).


Periodic index test results should be used to update the Kaplan 2D or 3D cams to maximize

efficiency of the turbine.

Projects such as digital governor conversions, retrofits, mechanical upgrades that are justified

by a poor CI or poor reliability indices should be implemented.

As the condition of the governor changes, the CI and reliability indices are trended and


programs to bring the governor back to an acceptable condition and performance level.


Baseline Knowledge:

ASME, The Guide to Hydropower Mechanical Design, HCI Publications Inc., 1996

Elliott, Thomas C., Standard Handbook of Powerplant Engineering, McGraw Hill

Publishing, 1989

Woodward Governor Company, The Woodward Way, 1977

Creager, William P., Hydroelectric Handbook, John Wiley & Sons, 1950

USBR, FIST Volume 2-3, Mechanical Governors for Hydroelectric Units, September 1990

Woodward Governor Company, Top Performance Through Conversion, Bulletin 09026

Woodward Governor Company, Equipment Maintenance Practices, Bulletin PMCC-24


Goncharov, A., Hydropower Stations – Generating Equipment, Moskva, 1972

State of the Art


Clarke-Johnson, R., & Ginesin, S., Overhaul or Upgrade: Governor Decision Factors,

HydroVision 2007

Fox, A., Governor Oil Pump Condition Assessment, HydroVision 2008

HAP Condition Assessment Manual 2011, prepared by ORNL, Mesa and HPPi


Rev. 1.0, 12/15/2011 184

Standards:

ASME PTC 29- 2005, Speed-Governing Systems for Hydraulic Turbine-Generator Units

IEEE 125, 2007, Recommended Practice for Preparation of Equipment Specifications for

Speed-Governing of Hydraulic Turbines Intended to Drive Electric Generators

IEC 60308, 2005, International Code for Testing of Speed Governing Systems for Hydraulic

Turbines

IEC 61362, 2000, Guide for Specification of Hydraulic Turbine Control Systems


ASME PTC 18-2011, Hydraulic Turbines and Pump-Turbines,







Shut-Off Valves

Revision 1.0, 1/20/2012

HAP – Best Practice Catalog – Shut-Off Valves

Rev. 1.0, 1/20/2012 186



1.1.1 Butterfly Valve Components ................................................................................ 188

1.1.2 Spherical Valve Components ................................................................................ 189

1.1.3 Cone Valve Components ...................................................................................... 190

1.1.4 Knife Gate Valve Components ............................................................................. 190


1.2.1 Performance/Efficiency & Capability-Oriented Best Practices ....................... 191

1.2.2 Reliability/Operations & Maintenance-Oriented Best Practices ..................... 192





3.0 Operation and Maintenance Practices .............................................................................. 193


3.2 Operations .................................................................................................................... 194

3.3 Maintenance ................................................................................................................. 194



4.2 Data Analysis ............................................................................................................... 195




Rev. 1.0, 1/20/2012 187


Major Valve Applications in Hydropower facilities [1]

There are various applications of valves in hydropower facilities. It is necessary to first describe

different types of major valves to clarify the scope of this best practice document. Based on the

functions and services that valves provide, the major valves in a hydropower facility can be

categorized as shut-off valves, energy dissipating valves, flow control valves, pressure control

valves, air/vacuum valves, and bypass valves. Their functions and major features are addressed

as follows:

(1) Shut-off valves (also known as closure valves) – They are often installed at the

downstream end of a conduit or penstock, e.g., the inlet of the turbine scroll case. The

turbine inlet valve is used to shut off water supply to the turbine, allowing turbine

dewatering for inspection and maintenance without dewatering the penstock. This

feature is desirable for long penstock and high-head cases, particularly when two or more

units share a common penstock. This turbine inlet valve is also used to cut off the water

flow and stop the unit when the wicket-gates fail to close; particularly at the emergency

situation of load rejection and wicket-gate malfunction. Butterfly valves, spherical

valves, and cone valves are the most commonly used turbine closure valves in medium-

large scale hydro plants. Butterfly valves are used for the heads up to 122 meters (400

feet). Spherical valves are used for heads up to 1200 meters (4000 feet). Cone valves

can be used for heads up to 1750 meters (5700 feet).

(2) Energy dissipating valve – Water may be released from a reservoir through low level

outlet(s) for reservoir level control, downstream water demands, or minimum stream flow

requirements. Efficient energy dissipating valves were developed to improve the

operating characteristics and lessen stringent stilling basin requirements. Fixed-cone

dispersion valves are often used for controlling free discharge for heads up to 300 meters

(1000 feet). Sleeve valves used to dissipate the head in a closed system without

cavitation damage (for heads up to 30 meters).

(3) Flow control valves – For large water conduits, energy-dissipating valves control the

flow of water while simultaneously breaking the head in the releases. Fixed-cone

dispersion and hollow-jet valves are used to control releases from low-level outlets, while

sleeve valves are used for flow control in ―in-line‖ piping systems. The flow control

valves are also used to regulate the flow of water to the runner in impulse-type

hydroelectric turbines (needle valves, as one part of Pelton turbine, are not discussed in

this BP). Although shut-off valves may be used to throttle flow, they are normally not

designed for continuous flow rate control.

(4) Pressure control valves – Pressure control valves can be further categorized as pressure-

relief, pressure-regulating and pressure-regulator valves. The pressure-relief valve opens

when the pressure acting on the valve reaches a preset value; it is often used as safety

device on air pressure tanks and on governor pressure set accumulators. Pressure-

regulating valves are often used to provide a regulated (constant) pressure source of air,

oil, or water in hydro facilities, by reducing their openings as upstream pressure rises.


Rev. 1.0, 1/20/2012 188

For example, when the penstock or unit inlet is the source of the powerhouse cooling

water, a pressure-regulating valve could be used to reduce the inlet pressure to the

required cooling water system pressure. The pressure-regulator valve is applied for

transient control, which opens to discharge the penstock flow simultaneously with rapid

wicket gate closure. This permits the penstock flow to remain relatively constant during

the load rejection. Flow control valves are commonly used for pressure-regulator service.

(5) Air/Vacuum valves – They are provided in piping systems to exhaust air from a penstock

system or spiral case, or to fill a vacuum to prevent conduit collapse.

(6) Bypass valves – They are applied where water is conveyed around a turbine, powerhouse,

or dam. Energy-dissipating and pressure-regulator valves are often used in bypass piping

lines. Needle valves and other valve types are also used in bypass lines to balance the

pressure across large butterfly or spherical valves before they are opened or closed.

Scope and Purpose of This Document

As the smaller valves on common mechanical piping systems have no difference to other

applications, this document focuses on the major valves typically applied in power water

conveyance systems at conventional hydropower plants. Therefore, this best practice will only

look at the shut-off valves installed at penstocks or power water conduits, including butterfly

valves, spherical valves, cone valves, and knife gate valves. The document addresses their

technology, condition assessment, operations, and maintenance best practices with the objective

to maximize performance and reliability.


Hydropower Facility → Water Conveyance → Control/Shut-off Valves

1.1.1 Butterfly Valve Components

Butterfly valves use a disc that rotates ninety degrees to open and close the valve.

Performance and reliability related components of a butterfly valve consist of the valve

body, valve seal, and the disc.

Figure 1: Butterfly Valve Example


Rev. 1.0, 1/20/2012 189

Valve Body: The valve body‘s purpose is to house the disc and attach the valve to the

piping system. Typically, the body has flanged connections to facilitate dismantling.

Valve Seat: The valve seat is on the contact portion of the valve body and is usually made

of flexible materials such as rubber or nylon, or metals like bronze or stainless steel. The

purpose of the seat is to seal the valve to prevent leakage through the valve when closed.

In high performance butterfly valves, the seat is offset from the shaft, therefore not

penetrated by the shaft. In triple-offset high performance butterfly valves, metal seats

may be used. In the triple-offset design, the seal contacts the seat only at the fully closed

position, without rubbing.

Disc: The function of the disc is to control the amount of water running through the pipe.

Because the disc is always present in the flow, there will always be a head loss across the

valve, even when the valve is fully open.

1.1.2 Spherical Valve Components

Spherical valves are valves that use a rotor, shaped like a ball, to stop or start the flow of

fluid. When the valve is opened, the ball rotates so the hole through the ball is in line

with the valve body inlet and outlet. When the valve is shut the ball is rotated so the hole

is perpendicular to the flow openings of the valve body, and flow stops.

Performance and reliability related components of a spherical valve consist of the body,

rotor, and the seals.

Figure 2: Spherical Valve Example

Body: The function of the body is to house the rotor and connect the valve to the rest of

the piping. The body is typically made of two or more flanged sections.

Rotor: The rotor has a cylindrical hole through it which controls the flow through the

valve. When open, the rotor is parallel to the flow direction, leaving the flow completely


Rev. 1.0, 1/20/2012 190

unrestricted. To cut off the flow through the valve, the rotor is turned 90° perpendicular

to the flow.

Seals: The seals reduce leakage through the valve. Spherical valves are recommended to

have both upstream and downstream seals, where the downstream seal is the service seal.

The upstream seal is used for maintenance, such as replacing the service seal. Typically,

the seals are actuated with penstock water pressure.

1.1.3 Cone Valve Components

Cone valves are similar to spherical valves in that they have a plug which contains a full-

bore passage when open. The plug is cone shaped and is lifted from the seats and turned

ninety degrees to actuate. Metal-to-metal seats are standard.

Figure 3: Cone Valve Example

Performance and reliability related components of a cone valve consist of the body, plug,

and the seals.

Body: The function of the body is to house the plug and connect the valve to the rest of

the piping. The body is typically cast of iron or steel. The body contains two seat rings.

Plug: The plug is cast in the shape of a frustrum of a cone and has a full bore passage

with seats which mate to the body in either the open or closed position.

Operator: (not shown in Figure 3) The operator may be manual, electric powered,

hydraulic powered, or pneumatic powered.

1.1.4 Knife Gate Valve Components

Knife gate valves use a plate which moves linearly into and out of the flow path to close

and open the valve.


Rev. 1.0, 1/20/2012 191

Figure 4: Knife Gate Valve Example

Performance and reliability related components of a knife gate valve consist of the body,

gate, seats, packing, and operator.

Body: Valve bodies are typically cast stainless steel up to 24‖, and fabricated in larger

sizes. Wafer and lugged (shown in Figure 4) bodies are available. End to end dimension

is small compared to spherical and cone valves.

Gate: Fabricated from plate, with edges and surface finished for sealing at the packing

and seats.

Seats: Where the gate meets the body when closed. Can be metal, which can leak a

small amount, or resilient which are designed to be drip-tight.

Packing: Seals around the gate where the gate exits the body. Packing and packing

gland are relatively large on a non-bonneted valve as shown in Figure 4. Bonneted

valves are available which fully enclose the gate, including when the valve is open, and

only the operating stem must be sealed. Rising stem and non-rising stem designs are

available.

Operator: Manual, electric, hydraulic, and pneumatic actuation is typical.


1.2.1Performance/Efficiency & Capability-Oriented Best Practices

As an integral part of the penstock, routine monitoring of head loss through

penstocks includes valves.

Routine monitoring to ensure that valves are in the correct position, e.g., fully

open when intended and fully closed when intended.

Routine monitoring to ensure that valve actuators function, and time to open and

close is as specified.


modification to equipment is made.


Rev. 1.0, 1/20/2012 192

Include industry acknowledged ―up to date‖ choices for valve components‘


1.2.2Reliability/Operations & Maintenance-Oriented Best Practices


Regularly inspect joints for leakage.

Valves should be used within the specified pressure-temperature range. Spherical

valves are capable of entrapping fluid in the internal cavity, which if heated can

cause a rise in pressure. It must be ensured that in this condition, the pressure in

the valve does not exceed the rated pressure for the attained temperature.



Civil – Penstock/Tunnel/Surge Tank best Practice




Mechanical – Raw Water System Best Practice



Butterfly valves are from a family of valves called quarter-turn valves and it derives its name

from the way that a ―butterfly-shape image‖ appears to form as it turns. The "butterfly" is a

metal disc mounted on a shaft. When the valve is closed, the disc is turned so that it is tightly

pressed against the seats, sealing off the passageway. When the valve is fully open, the disc

is rotated a quarter turn so that it allows an almost unrestricted passage of the process fluid.

The valve may also be opened incrementally to regulate flow. Unlike a ball valve, the disc is

always present within the flow; therefore a pressure drop is always induced in the flow

regardless of valve position [3].

Resilient seated butterfly valves were developed first. High performance butterfly valves, in

which the shaft and seat are offset, were the next. Triple-offset high performance butterfly

valves are the most advanced design. Triple-offset butterfly valves are utilized for high

pressure and temperature conditions, and can have resilient or metal seats.

http://www.cbs.grundfos.com/CBS_Master/lexica/AC_Butterfly_valve.html


Rev. 1.0, 1/20/2012 193

Spherical valves are specialty items, typically designed for the individual application. They

are made for high pressure, high velocity, and large diameter applications found in

hydroelectric facilities.

Spherical valves, on the other hand, have not been around nearly so long. A spherical ball-

type, all-brass valve patented in 1871 led to the invention of the modern ball valve.

Unfortunately, the valve was not successful and was not even mentioned in valve catalogs of

the late 1800s. Nearly 75 years later, the first resilient seated ball valve patent was issued in

April 1945. However, ball valves were not commercially available until the late 60s [6].


In order to enhance the performance of valves, computer aided design (CAD) software is

now used throughout the design process. Companies utilize top-of-the-line solid modeling

software and finite element analysis programs to calculate stress and deflection of the valve

components. With this information, developers can include proper relief and stress factors to

assure a long valve life.

Another advantage to CAD software is that it can then be loaded onto a computer numerical

controlled (CNC) machine. These machines can fabricate valves with tremendous precision

and consistency.



After the commercial operation begins, how the valves are operated and maintained will have

a huge impact on maintaining reliability. Condition assessment of the valves must address

any past damage, location of damage, and repeat damage.

Typical valve distresses include the following:

Shaft assembly wear, indicated by displacement between the shaft and bushing

Seal condition

Corrosion, usually caused by environmental factors, is suggested by loss of steel

Cracking, found during dry inspection

Abnormal noise/jumping/vibration, discovered during valve operation [7]

For spherical valves, close attention should be given to the condition of the seals.

http://ezinearticles.com/?Ball-Valve-History-and-Mystery&id=123681


Rev. 1.0, 1/20/2012 194

3.2 Operations

Butterfly valves cause a head loss in the flow through the valve. Head loss increases as

design pressure or head increases because the disc and shaft size increase with pressure.

Although head can be significantly reduced across partially open butterfly valves, prolonged

throttling operation is not recommended as it can result in cavitation damage to the disc, seal,

or body [1].

On spherical valves, moveable seals reduce leakage when the valve is closed. Valve opening

and closing sequencing controls should preclude seal damage by valve rotation when seals

are extended. It is recommended that spherical valves have both upstream and downstream

seals. The upstream seal should be used as the maintenance/emergency seal and the

downstream seal should be used as the service/working seal.

Rapid valve closure can result in damaging pressure transients. Opening/closing times and

operating pressures should be recorded for future testing comparison.

During plant operations, it is important to routinely inspect the exterior surfaces of valves for

signs of leakage while the valves are under hydrostatic pressure. If any leaks are discovered,

the source should be promptly identified and repair performed.

3.3 Maintenance

In order to avoid valve failure during operation, all valves should be periodically inspected to

determine wear of the components and replace parts accordingly. The working conditions

and location of the valves should determine the frequency of the inspection and maintenance.

The valve manufacturer should have information on how to best maintain their valves.

For spherical valves equipped with both upstream and downstream seals, the upstream

maintenance seal allows replacement or maintenance of the working seal when the valve is

closed under full pressure. However, the upstream seal should have a positive mechanical

locking system on the seals to prevent accidental opening while working on the downstream

seal [1].



For shut-off valves, the measure of performance is a direct result of their functionality. The

purpose of the valves is to stop the flow of water and keep water away from the portions of

the system being isolated. Each valve and its associated actuator must be able to fully open

and close within the intended time.

Plant efficiency is not greatly affected by shut-off valves because the valves are normally a

small fraction of the total water delivery system. It is important that these valves function


Rev. 1.0, 1/20/2012 195

properly not necessarily for efficiency, but for safety. Equipment and workers performing

tasks in dewatered portions of the plant must be protected. Valve leakage can be tolerated as

long as safety and equipment protection are not compromised.

Leakage rates should be measured and recorded. Large valves, even those designed to be

drip tight when they are new, may leak after years of service.

4.2 Data Analysis

Leakage through shut-off valves can be tolerated as long as equipment protection and safety

are not compromised. Relatively small amounts of leakage can be tolerated and handled by

pumping water out of areas where maintenance will be performed. However, if pumping

becomes excessive, the cost of new seals or other corrective actions may be justified.


The field test results for leakage and actuator stroke time should be included when updating

the plant‘s unit performance records. These records shall be made available to all involved

personnel and distributed accordingly for upcoming inspections.


Baseline Knowledge:


State of the Art:

―Valve Types.‖

Integrated Publishing, n.d. Web. 20 Dec. 2011.

http://www.tpub.com/fireman/69.htm

―Butterfly Valve.‖

Grundfos.com. n.d. Web. 20 Dec. 2011.

<http://www.cbs.grundfos.com/CBS_Master/lexica/AC_Butterfly_valve.html>

Konigsmark, Hugh. ―A Review of Butterfly Valve Components and Operation.‖

ChemicalProcessing.com. n.d. Web. 20 Dec. 2011.

<http://www.chemicalprocessing.com/articles/1998/300.html>

Sundaram, Kannan. ―Why a Butterfly Valve.‖

Piping and Valve Engineering. 4 June 2008. Web. 20 Dec. 2011.

<http://piping-valves.blogspot.com/2008/06/why-butterfly-valve.html>


Rev. 1.0, 1/20/2012 196

Mayer, Johnny. ―Ball Valve History and Mystery.‖

EzineArticles.com. 5 Jan. 2006. Web. 20 Dec. 2011.

<http://ezinearticles.com/?Ball-Valve-History-and-Mystery&id=123681>.

―REMR Management System for Tainter and Butterfly Valves.‖

REMR Technical Note OM-MS-1.11. 1998. Web. 20 Dec. 2011.

http://www.wes.army.mil/REMR/pdf/om/ms-1-11.pdf

Standards:

ASME B31.1. 2010. ―Power Piping.‖

ASME International. New York, NY. 2010

ASME B16.34. 2009. ―Valves—Flanged, Threaded, and Welding End.‖

ASME International. New York, NY. 2009

http://www.wes.army.mil/REMR/pdf/om/ms-1-11.pdf


Raw Water System

Revision 1.0, 1/19/2012

HAP – Best Practice Catalog – Raw Water System

Rev. 1.0, 1/19/2012 198



1.1.1 Raw Water System Components .......................................................................... 199

1.2 Summary of Best Practices ........................................................................................ 202

1.2.1 Performance/Efficiency & Capability - Oriented Best Practices ..................... 202

1.2.2 Reliability/Operations & Maintenance - Oriented Best Practices ................... 202







3.2 Operations .................................................................................................................... 208

3.3 Maintenance ................................................................................................................. 211



4.2 Analysis of Data ........................................................................................................... 213




Rev. 1.0, 1/19/2012 199


This best practice addresses the technology, condition assessment, operations, and maintenance

best practices for raw water systems, focusing on cooling raw water, with the objective to

maximize performance and reliability. The raw water cooling system is a once–through (open

loop) system, in which water flows are discharged back to the tailwater. The primary purpose of

the raw water system is to supply water sources to any or all of the following cooling and other

water systems:

Turbine and generator bearing coolers

Turbine shaft seal

Generator air coolers

Generator fire deluge

Transformer and/or exciter coolers

Heating, ventilation and air conditioning

Service Water

Source for potable water treatment equipment

Fire protection [1]


Hydropower Facility → Powerhouse → Power Train Equipment → Balance of

Plant/Auxiliary Components → Raw Water System

1.1.1 Raw Water System Components

The raw water system is critical to unit operation in its global plant cooling function. The

reliability related components of raw water systems include the supply intake, strainers,

pumps, valves, generator air coolers, piping and instrumentation/monitoring. The raw

water system is fed either from the units‘ forebay, penstock, or scroll case or pumped

from the tailrace/tailwater. Tailrace/tailwater is normally the source for lower head

plants. Forebays, penstocks or scroll cases is normally the source for higher head plants.

The water source is therefore defined as either gravity or pumped type cooling system. In

all plants, an intake for unit cooling, sealing and lubrication water is provided for each

unit with the supply lines between units manifolded or cross connected for flexibility.

Figure 1 is a typical schematic of the raw water system and it shows the comprehensive

nature as it services a wide variety of other hydropower systems.


Rev. 1.0, 1/19/2012 200

Figure 15: Typical Raw Water System Piping Schematic [2]


Rev. 1.0, 1/19/2012 201

Supply Intake: The function of the supply intake is to feed the raw water system with

river, dam or untreated water. Unit cooling, lubricating and sealing water pressure is

usually supplied at a maximum pressure of 40 pounds per square inch (around 28 m of

water) to prevent damage to the generator air coolers and other equipment.

Strainers: The function of the strainer is to remove suspended solid material (wood,

rocks, sand, biological matter, etc) from the raw water to minimize fouling of the

generator air coolers and oil cooler heat exchangers. The strainer must be back flushed

when the differential pressure across the strainer reached a set point value to ensure the

raw water flow rate is not reduced due to blockage of the strainer.

Pumps: The function of the raw (cooling) water pumps, if so equipped, is to develop

sufficient flow and head to meet the requirements of the equipment it services. This

ensures the water in the piping, strainer, valves and air coolers will be supplied at

required flow and pressure. The design must allow for the operation of the raw water

component in a fouled condition. Higher head plants/units normally do not require

pumps.

Valves: The function of the valves within a raw water cooling system is to route,

regulate, or isolate as required, the flow of water. There are multiple types of valves and

designs based on their specific application. Chief among these are gate, butterfly, globe,

control, ball and check valves. In the high head plants pressure must be reduced by

pressure regulating valves for most raw water services. A relief valve on the low-pressure

side of each pressure regulating valve protects against piping or equipment damage which

might result from over pressurization resulting from faulty operation of the valve. A

proportioning valve is used to control the flow of cooling water to the generator air

coolers.

Generator air coolers: Generator air coolers, which are considered as part of the

Generator (see Best Practice Catalog - Generator), are heat exchangers located in the

generator air housings which employ raw water to cool circulating air which in turn cools

the generator. Cooling water is delivered to a header serving all air coolers. This header is

sized by the generator manufacturer to distribute approximately equal flow to each

cooler. From the air cooler water returns via another header to a discharge chamber

designed to keep the air coolers full of water at all times. The cooling water headers are

normally circular.

Piping: The function of the piping is to connect supply water from the forebay/

penstock/scroll case/tailwater to rest of the system at the design water flow rate and

pressure to achieve optimum cooling of system components.


Rev. 1.0, 1/19/2012 202

Instrumentation/Monitoring: The function of the instrumentation is to measure, monitor

and regulate the process variables of the raw water, such as flow, temperature and

pressure. Pressure indicators, flow meters, temperature indicators, differential pressure

transmitters, and/or sightglasses are examples of key instruments.



Please cross reference to the associated best practices that have been identified

for the generators, turbines and transformer that served by the raw water

system.


Follow the best practices in the Best Practice Catalog - Trash Racks and

Intakes for the raw water supply.

Use Remote Operated Vehicle for internal condition inspection on large size

pipe (> Ø4‖).

Install isolation valves at selected locations for raw water pipeline so key

equipment can be isolated and removed for internal inspection as necessary.

Develop, implement and maintain a raw water instrumentation calibration and

verification program for instrumentation such as generator air cooler

thermocouples, flow meters, and proportioning valve controllers and

differential pressure gages.

When replacing raw water piping, select materials of construction for generator

cooling water (such as carbon steel or stainless steel) and base decisions on

specific generating units requirement (such as water quality and plant

economics).

Observe the strainer unit; it will give the operator a good indication of the

quality of the raw water supply.

Operate centrifugal pumps within the Equipment Reliability Operating

Envelope (EROE) to achieve maximum Mean Time Between Failures

(MTBF).

Change impeller diameter, if required, to ensure that every raw water

centrifugal pump operates inside its EROE.

Keep EROE range between + 10% to –50% in flow from the pump best

efficiency point.


Rev. 1.0, 1/19/2012 203

Keep raw water centrifugal pump curves in the control room. Operators should

be trained and instructed on their use for optimizing centrifugal pump safety

and MTBF.

Monitor the raw water pump flow range by inputting the pump shop test curve

and collecting transmitter signals (inlet pressure, discharge pressure and flow)

into spreadsheets to calculate the pump head and flow.

Adjust head of the raw water supply as required to facilitate the pumps

operation within the EROE.

Label raw water system piping with colored tape to help personnel to

understand system operation and how to take corrective action quickly to

prevent unit performance or availability issues.

Installation of raw water strainers with automatic backwash capabilities will

reduce labor intensity associated with maintaining acceptable strainer pressure

differentials especially at locations that are not continuously staffed.

Place a higher priority on removal of generator air cooler bio-fouling than the

bio-fouling of the raw water pipe unless it has reduced the flow to a level

below the design flow.






Mechanical – Generator Best Practice

Civil – Trash racks and Intakes Best Practice


Rev. 1.0, 1/19/2012 204



Early designs for raw water systems consisted mainly of carbon steel and cast iron pipe

fittings, pumps, valves and other fixture components. Controls and instrumentation were

rudimental, analog and predominately manually operated. Piping embedded in concrete was

cast iron with bell and spigot joints requiring leaded joints at connection points with external

piping. Piping insulation (where used) contained asbestos fibers.

Valves used for isolation and routing were predominately manually operated gate or globe

type valves. An air operated thermostatically controlled proportioning valve was used to

regulate flow through the generator air coolers to control generator temperature. A single

strainer that was manually operated served the entire raw water system. For lower head

plants, centrifugal pumps were used to provide forced circulation to generator air and oil

coolers.

Generally few provisions were made for back-flushing air or oil coolers. Water for fighting

fires was provided by elevated storage tanks. Fire protection systems were manually

actuated.


The basic design concepts for raw water systems at hydro plants have not changed

substantially. However, there are a number of component design improvements for raw

water systems that have become state of the art. Most of these changes have been driven by

technical improvements in materials of construction and the cost of materials such as

stainless steel and copper/copper alloys.

Materials of construction selection for raw water piping systems and components is based on

the specific characteristics of the system including water quality of the raw water supply

(suspended solids, tendencies to scale, potential bio-fouling, potential for corrosion, etc.) .

Exposed larger bore piping (> Ø4‖) can be flanged or butt welded carbon steel or stainless

steel. (Flanged piping allows disassembly of piping systems for internal build-up cleaning

out.) Small bore piping is non-corrosive material such as stainless steel. Embedded piping is

stainless steel or cement lined ductile iron (for larger bore piping) with flanged joints for

external piping connections.

Valves larger than Ø6‖ are normally gate valves. Isolation valves Ø2½‖ to Ø6‖ are normally

butterfly valves. Stainless steel ball valves are normally used for Ø2‖ and smaller valves.

Valves are manually operated or automated based on the process requirements, staffing

levels, and etc. Closed cell foam piping insulation systems for eliminating external piping

condensation have replaced asbestos containing systems. Raw cooling water pump design


Rev. 1.0, 1/19/2012 205

has been changed very little over time. However, mechanical seals have replaced packing

glands. Advances in pump materials of construction, impeller design and manufacturing, and

more efficient motor design provide improvements in pump reliability and operating costs.

Modern raw water pump set-up Figure 2.

Figure 16: Typical Dual Raw Water Pump Set-Up

Current raw water system designs include stainless steel duplex automatic backwash strainers

(see Figure 3). Subsystems such as turbine seal water and fire protection can be equipped

with finer mesh automatic backwash strainers for additional reliability of these systems.

These automated features are used as labor saving methods, especially suitable for facilities

that are not continually staffed.


Rev. 1.0, 1/19/2012 206

Figure 17: Section View of Typical Automatic Backwash strainer [SERFILCO]

The automated backwash strainers include instrumentation and controls to initiate strainer

cleaning based on a time cycle or a pre-established strainer pressure differential.

Fire protection systems are equipped with diesel driven booster pumps which replace the

traditional elevated fire water storage tanks. Depending on the individual hydro plant

economics, booster pumps may be able to provide increased volume and pressure in fire

fighting situations than elevated water storage tanks. Fire protection systems are automated

with designs mandated by fire codes that were nonexistent in the early twenty century.


Rev. 1.0, 1/19/2012 207



The supply intake for the raw water system can be assessed at two locations depending on the

plant layout. If the penstock is tapped for the raw water supply then the trash rack condition

assessment becomes critical for the same reasons that the turbines must be supplied debris

free water. If the raw water is drawn from the trail water then the intake structures of raw

water supply become important. In both cases see the condition assessment best practices in

the Best Practice Catalog Trash Racks and Intakes. Unusual biological fouling by plants,

fauna, fish and flood debris is a real issue, varies widely, and must be evaluated for specific

sites.

Raw water pipe is difficult to evaluate for wall thickness or pinhole leaks. ―D‖ meter

readings of wall thickness are considered unreliable due to fouling on the inside of the pipe

that may be ½ to ¾ of an inch on Ø6-8‖ pipe. Pinhole leaks may ultimately develop along the

length of the piping system so replacement is typically justified.

The best practice for assessing the internal condition of the larger sized raw water pipe line is

a camera mounted Remote Operated Vehicle, Figure 4.

Manual valves can be operated to determine proper operation. Condition of disc, seats and

other internal components would require removal from the pipe connections. A system that

uses strategically located isolation valves enables this removal. Therefore, it is best practice

to install isolation valves at selected location throughout the raw water system so that key

equipment can be isolated and removed for internal inspection and/or repaired as required.

The additional valve has little or no impact on the efficiency of the raw water system except

for the head losses across the valve.

Figure 18: Remote Operated Vehicle (ROV) for

pipeline inspection of raw water system [Substructure, Inc.]


Rev. 1.0, 1/19/2012 208

The raw water system requires instrumentation to monitor and provide information to help

control system equipment such as pumps and strainers. Instruments should be checked and

re-checked for accuracy, especially air cooler thermocouples, stator core Resistance

Temperature Detectors (RTDs), flow meters, shunt voltage readings, proportioning valves

controller, and isolation valve operators. Operability of the proportioning valves can be

readily determined as to whether the valves are adjusting water flow for variations in air

temperature. The correct function must be determined by the supplier‘s Original Equipment

Manufacturers (OEMs) engineering documents. Some temperatures can be checked with

hand held thermocouples, heat guns, and thermal imaging equipment, depending on

accessibility. Differential pressure gauges should be checked to ensure operability and

accuracy. A common problem with differential pressure gauges is fouled or blocked pressure

tubing.

Materials for Generator Cooling System piping may be cast iron, carbon steel, or stainless

steel. The hydraulic performance for each type is detailed in numerous piping industry

handbooks; Cameron Hydraulic Data is highly regarded [5]. As a best practice, the most

common material would be ASME B36.10 Welded and Seamless Wrought Steel Pipe [6],

constructed to ASME B31.3 Process Piping [7] standard.

The strainer unit will give the operator a good indication of the quality of the raw water

supply. The best practice for evaluating the raw water strainer condition is based on two

indicators, pressure differential trend data across the unit and the strainers performance after

a back flush to operate at rated pressure drop or lower.

3.2 Operations

When it comes to the operation of a raw water system, how the pumps are efficiently used is

critical to the cooling process. It is best practice to operate centrifugal pumps within the

Equipment Reliability Operating Envelope (EROE) to achieve maximum Mean Time

Between Failures (MTBF). The EROE, also called the heart of the curve (Figure 5), assures

maximum centrifugal pump MTBF by avoiding all operating areas of hydraulic disturbances.

An established best practice for the EROE range should be + 10% to – 50% in flow from the

pump best efficiency point.


Rev. 1.0, 1/19/2012 209

Figure 19: Centrifugal Raw Water Pump - component damage as function of operating point

Many new raw water pumps are selected with impeller diameters that are incorrectly sized

for field operation parameters. The hydraulic calculations used to determine the pump head

required for centrifugal pumps will only approximate the field conditions, and can be

conservative, which will result in different field head required than noted on the pump data

sheet. This can result in driver overload/underload and possible cavitation. Failure to

establish EROE limits will lead to low MTBF of centrifugal pumps. Approximately 80% of

centrifugal pump reliability reductions (causes of low MTBF) are due to process changes,

which cause the pump to operate in either a high flow or low flow range. This exposes the

pump to hydraulic disturbances resulting in low MTBF. Establishing operator EROE targets

for all critical site pumps and all ―bad actor‖ pumps (pumps with one or more components

failures per year) will ensure optimum centrifugal pump safety and MTBFs.

It is best practice to ensure that every raw water centrifugal pump operates inside the EROE

and change impeller diameter if required. Lower pump head required can force centrifugal

pumps to operate at greater flow than the design point. Most centrifugal pump drivers are

sized for +10% power and can be overloaded if the pump flow is greater than the design

flow. The most cost effective solution to prevent driver overload is to reduce (cut or trim) the

pump impeller diameter, to arrive at the desired pump flow under the required conditions of

actual field process head.


Rev. 1.0, 1/19/2012 210

The safety and reliability of all centrifugal pumps is optimized if pumps are operated within

the equipment reliability operating envelope. It is best practice to have raw water centrifugal

pump curve available in the control room and operators need to be trained for using pump

test curves to optimize centrifugal pump safety and MTBF. Centrifugal pumps produce flow

inversely proportional to the required process head. This flow range is obtained by having

operations aware of the centrifugal pump characteristic, providing process targets and having

the pump test curves available for each pump for operator use and understanding.

Unnecessary centrifugal pump maintenance and pump failures result from operators not

checking the pump test curves, or not confirming that the pump operates within its EROE

and not understanding their use.

It is an instrumentation best practice for monitoring, in the control room, the raw water pump

flow range by inputting the pump shop test curve and collecting transmitter signals (inlet

pressure, discharge pressure and flow) into spreadsheets to calculate the pump head and flow.

Even if flow meters are not installed for each pump, EROE targets should be established by

other methods (control valve position, motor amps, pump inlet and discharge piping

differential temperature). Critical centrifugal and ‗bad actor pumps‘ require constant

surveillance by operators to ensure optimum safety and reliability.

It is a best practice to adjust head as required. Head required in raw water pumping system

can be changed by adjusting the discharge system resistance using pressure control, flow

control or level control. Each of these methods results in closing a throttle valve in the

discharge piping which increases the head (energy) required and reduces the flow rate. This

action requires more energy (head) to overcome the increased system resistance.

Using colored labels or paint to define each individual line of the system (supply lines, return

lines, bypass lines) involves personnel and promotes ownership thus increasing system safety

and reliability. It is a best practice to label raw water system piping to ASME A13.1 [8] with

correct colored labels. This will help personnel understand the system operation.

Color coded and identified piping greatly increases site personnel awareness of raw water

system operation. See in Figure 6 as an example of piping labels. Many critical machine unit

shutdowns are the result of not monitoring the local instrument and components in the

system. Failure to properly label piping, instruments and components leads to neglect and

corresponding low the system reliability.


Rev. 1.0, 1/19/2012 211

Figure 20: Piping Labeling from ASME 13.1 [8]

Proportioning valves control the raw water flow to the generator air coolers for maintaining

proper generator air temperature. The benefit of the proportioning valve is in a situation

where the generator is operating in load following mode with significant changes in MVA

output. The valve controller would be set to the desired air temperature. Generator air cooler

flow balancing is a common operational procedure and should be readily accomplished by

plant staff. Air cooler discharge temperature should be checked from each cooler to ensure

uniform cooling.

3.3 Maintenance

The raw cooling water to the strainer performance condition is typically judged by the

differential pressure across the strainer (Figure 7).


Rev. 1.0, 1/19/2012 212

Figure 21: Typical differential pressure gauge with feedback switch [EATON]

However, high differential is due to fouling of the strainer which can be corrected by

installing a back flush feature. Most strainers are designed with a 1/16‖ to 1/32‖ screen

size to allow small particles to pass for scouring action in the pipes and heat exchanger

tubes. If the strainer elements are failed, the strainer is essentially a piece of pipe which

does not remove the larger and detrimental debris. Unusual biological fouling, including

small fish (shad) and flood debris, can present a problem, but should normally be

corrected with a well designed back flush system. The strainer should require minimal

maintenance except to replace the internal elements that may degrade with time.

The generator raw water pipe and generator air cooler tubes foul in any system. The

cleaning of the raw water pipe is probably of minimum value unless the fouling actually

reduces raw water flow to below design value. The generator air cooler tubes are much

more of an issue and require periodic cleaning to maintain acceptable performance.

With modern air cooler design, the efficiency of the air cooler will be very similar to a

counter flow heat exchanger. The old generator air coolers were similar to a cross flow

heat exchanger with a much reduced thermal efficiency. The best measure is the

difference between the raw water cold inlet temperature, and the cold air discharge

temperature. The raw water temperature is the theoretical temperature as to how much

the cold air temperature can be lowered.


Rev. 1.0, 1/19/2012 213

Typical efficient coolers will have a cold air discharge temperature of approximately 5°C

above the raw water inlet temperature. In the case of badly fouled tubes and degraded

fins, the air temperature approach to the raw water temperature may be 15°C to 20°C. In

the case of 30°C water inlet temperature, the maximum design air temperature of 40°C

would be exceeded and the cold air temperature would be 45°C to 50°C.



The Raw Water System includes cooling water pumps (for plants/units that are so equipped),

piping, valves, strainers, instrumentation and controls. As an auxiliary system, the condition

of the Raw Cooling Water system components can affect the performance and reliability of

the generating plant/unit(s).

Plant/unit performance measures include Equivalent Availability Factor (EAF) and

Equivalent Forced Outage Factor (EFOR), Maintenance Outage Rate (MOR) and Planned

Outage rate (POR). These indicators are used universally by the power industry. Many

utilities supply data to the Generating Availability Data System (GADS) maintained by

NERC. This database of operating information is used for improving the performance of

electric generating equipment. It can be used to support equipment reliability and availability

analysis and decision-making by GADS data users.

Periodic fielding testing/evaluation of Raw Cooling Water system components that are noted

as contributors to decreases in plant/unit availability should be conducted. Periodic testing

includes cooling water pump flow tests, pipe/cooler fouling investigations, internal valve

and/or strainer inspections or other tests identified.


The reliability of a generating unit, including its auxiliary support systems, can be monitored

through reliability indexes or performance indicators as derived according to NERC‘s

Appendix F, Performance Indexes and Equations [9].


As raw water system components are identified as contributors to decreases in plant

performance and availability or increases in maintenance costs, field testing of the

specifically identified raw water system component(s) is (are) performed. The field test

results are trended and analyzed. Using the data collected and analyzed, projects to eliminate

or mitigate any identified degradation or high maintenance component issues are developed,

ranked and justified in the Capital and Maintenance funding programs. Capital and

Maintenance projects that are approved are implemented to return the component to an

acceptable condition and performance level. Post implementation testing of components that


Rev. 1.0, 1/19/2012 214

are replaced/modified or otherwise repaired is conducted to verify that issues that resulted in

decreased unit/plant performance and/or reliability have been addressed.


Baseline Knowledge:

EPRI, TR-112350-V4 Hydro Life Extension Modernization Guides: Volume 4-5 Auxiliary

Mechanical and Electrical Systems– Palo Alto, CA – 2001


TVA, Technical report No.24 Mechanical Design of Hydro Plants, US Government Printing

Office – Washington - 1960

State of the Art:

Forsthoffer, W., E., Best Practice Handbook for Rotating Machinery – 2011

Heald, C., C., Cameron Hydraulic Data – Nineteenth Edition -2002

Standards:

ASME A36.10, Welded and Seamless Wrought Steel Pipe - 2004

ASME B31.3, Process Piping ASME Code for Pressure Piping – 2008

ASME A13.1, Scheme for Identification of Piping Systems -2007

NERC, Appendix F, Performance Indexes and Equations - January, 2011


Generator

Revision 1.0, 12/20/2011

HAP – Best Practice Catalog – Generator

Rev. 1.0, 12/20/2011 216

Contents 1.0 Scope and Purpose .................................................................................................... 217

1.1 Hydropower Taxonomy Position .......................................................................... 217

1.1.1 GeneratorComponents ....................................................................................... 217

1.2 Summary of Best Practices ................................................................................... 227

1.2.1 Performance/Efficiency & Capability – Oriented Best Practices ..................... 227

1.2.2 Reliability/Operations & Maintenance Oriented Best Practices ....................... 228

1.3 Best Practice Cross-references .............................................................................. 229

2.0 Technology Design Summary .................................................................................. 229

2.1 Material and Design Technology Evolution ......................................................... 229

2.2 State of the Art Technology .................................................................................. 230

3.0 Operation and Maintenance Practices ...................................................................... 232

3.1 Condition Assessment ........................................................................................... 232

3.2 Operations ............................................................................................................. 234

3.3 Maintenance .......................................................................................................... 235

4.0 Metrics, Monitoring and Analysis ............................................................................ 236

4.1 Measures of Performance, Condition, and Reliability .......................................... 236

4.2 Data Analysis ........................................................................................................ 237

4.3 Integrated Improvements ...................................................................................... 238

5.0 Information Sources ................................................................................................. 238


Rev. 1.0, 12/20/2011 217


The best practice for the electrical generator addresses its technology, condition assessment,

operations, and maintenance best practices with the objective to maximize the unit performance

and reliability. The primary purpose of the generator is to covert the mechanical torque supplied

by the turbine to electrical power.

The manner in which the generator is designed, operated, and maintained provides significant

impact to the efficiency, performance, and reliability of a hydropower unit.


Hydropower Facility → Powertrain Equipment → Generator

1.1.1 Generator Components

The entire generator assembly is typically referred to as a ―machine‖ and its performance

is typically defined by the rated MVA, KV and Power Factor (PF). The major

components of a generator, shown in Figure 1, are addressed in this section. Among the

main generator components listed below, the stator, the cooling system and the rotor have

significant impact on the unit efficiency.

Figure 1: Cross Sectional View of a Generator

Stator: A stator consists of stator winding and stator core. The stator winding, also

known as the armature, includes its physical supports and electrical connections. The

stator windings are where mechanical energy is converted to electrical energy by

interaction with the rotating air gap flux provided by the rotor. The stator windings

(sometimes referred to as ―bars‖ or ―coils‖) are comprised of electrically insulated copper

conductors connected such that the design voltage and power requirements are achieved.


Rev. 1.0, 12/20/2011 218

The stator winding insulation functions to withstand voltage without failure and is one of

the most critical subcomponents affecting reliability. The copper conductor cross section

and material and the electrical span of the coils have a direct influence on the stator

copper losses. These stator windings are recessed in and supported by the slots formed by

assembly of the laminated core. The stator core provides primary support of the straight

portion of the stator winding. The core also provides the magnetic circuit‘s path essential

for the generation of a voltage with the resultant power flow through the winding. The

core is comprised of a stack of thin laminations of highly permeable steel in order to

reduce core losses. Each lamination has a thin coating of insulating varnish that

electrically insulates it from the adjacent lamination to reduce eddy current losses in the

core.

Figure 2 shows a stator section viewed in a radial direction with the rotor removed from

the machine. Predominate features in this figure are the winding and the core. A section

of core laminations can be seen in an axial view in Figure 3. This figure shows only a

portion of the core in the process of being stacked. The ―slot‖ (area between the fingers)

on the air gap side provides support for the winding and core attachments to the stator

frame.

Figure 2: Windings and Core Figure 3: Core Laminations Being

“Stacked”

Neutral Grounding: The grounding method of a wye connected generator can serve

several purposes. The grounding components are not performance related and their

purpose is to protect the generator and associated equipment against damage caused by

abnormal electrical conditions and as such they are classified as reliability components

for purposes of this BP. This is accomplished by the following.

Minimizing damage to the stator core caused by internal ground faults

Providing a sensitive means of ground fault detection

Limiting transient overvoltage stress on generator stator insulation and

Limiting mechanical stress on the generator for external ground faults


Rev. 1.0, 12/20/2011 219

The grounding method and components chosen will determine to what degree each of the

above objectives is satisfied. This may include no components for an ungrounded system

or a resistor, a reactor (inductor) or a distribution transformer and secondary resistor on

grounded systems. Figure 4 depicts a typical single-line sketch showing schematically a

unit grounded with a high resistance distribution type transformer. This method typically

limits ground fault current to a value of 5 to 15 amps for a full phase to ground fault if the

secondary resistance is chosen properly.

Figure 4: Typical Unit Single-Line Showing High Resistance Grounding

Some neutral grounding schemes employ a breaker and/or a disconnect switch to isolate

the unit in the event of a ground fault, or to accommodate maintenance activities.

Generator Cooling System: There are two basic types of cooling methods used for the

rotor and the stator. For indirect cooling, the heat generated in the electrical conductor

must flow through the ground medium before reaching the coolant (usually air). For

most units over 10 MVA built since 1930, the generator housings are enclosed; prior to

this, the housing was open. In direct cooling, the coolant (usually water) is in direct

contact with the conductor.

Performance related components of the generator cooling system consists of fan blades

mounted on the rotor, raw cooling water (RCW) system, and generator air coolers. The

primary purposes of a generator cooling system is to provide adequate cooling for the

stator/field winding insulation material and limit thermal stresses to acceptable levels.

The excitation system may be cooled by the generator air coolers or with ambient air

depending on the design. This will reasonably ensure an acceptable life of the field and

stator insulation including the rotating excitations system (if used).


Rev. 1.0, 12/20/2011 220

SPIDER ROTORRIM

Upper Fan

ROTORPOLES

Lower Fan

STATORCORE

STATORFRAME C

oo

ler

Qft

Qrt

Qpt Qt

Qb

Qtot

Qst

Qyt

Qyb

Qsb

Qpb

Qrb

Qsit Qsot

Qsib Qsob

Qfb

A typical generator cooling system for enclosed housings will be composed of two fluid

flow paths to cool the generator. The air flow path is a closed system established by the

air housing which allows the air to be discharged from the fan blades and circulate

through the generator. The normal flow path is from the blades, by the field poles,

through slots in the generator iron core, into a large area in the frame, through the

generator air coolers into the air housing, then back to the fan blades by passing over

(under) the stator frame. Figure 5 shows a typical air flow schematic.

Figure 5: Typical Air Flow Schematic through a Generator

As a subsystem of the cooling system the Raw Cooling Water (RCW) system functions

as a heat sink for generator losses. The raw cooling water system is an open system in

which water flows are discharged back to the headwater or tailwater. A RCW strainer

removes suspended solid material (wood, rocks, sand, biological matter, etc) from the

RCW to minimize fouling of the generator air cooler heat exchanger. The strainer must

be back flushed when the differential pressure across the strainer reaches a set point value

to ensure the RCW flow rate is not reduced due to blockage of the strainer. RCW head

pressure or pumps and motors must develop sufficient flow and head to circulate water

through the piping, strainer, valves and air coolers. The valves in the system function to

open, close or moderate RCW to the various components. A Motor Operated Isolation

Valve (MOIV) may be provided that opens with a unit start signal and closes when the

unit shuts down. The proportioning valve is used to moderate water flow to typically

keep the generator cold air temperature at a certain value. Motive force for air flow

through the unit is provided by the fan blades. The fan blades are mounted on the

generator rotor therefore operating at synchronous speed. Typical rotor mounted fan

blades are seen in Figure 6. Some uprated generator cooling systems have baffles that

have the function of increasing fan pressure and air flow.

Generator

Center Line


Rev. 1.0, 12/20/2011 221

Figure 6: Rotor Mounted Fan Blades (top blade)

Non-performance but reliability related components of a Generator Cooling System

include the piping, air housing stator frame and core openings. The function of the piping

is to supply water from the penstock or RCW pumps to generator air coolers at the design

water flow rate to achieve optimum cooling of the generator components. The generator

air housing provides a boundary for the circulating air including the generator excitation

cooling system. The stator core vents provide a flow path for the cooling air to be

directed through the frame and core to the generator air coolers. Additionally some

ventilation systems are provided with a core bypass flow path which allows the air to go

into the annulus section of the stator frame and then the air coolers.

Thrust Bearing and Cooling System: Units are classified mechanically by the location of

the thrust bearing relative to the rotor as follows.

For a suspended unit, the thrust bearing is above the rotor and there may be one or two

guide bearings one of which is always above the rotor.

In an umbrella arrangement, the thrust bearing is on the bottom side of the rotor usually

with an integral guide bearing.

The modified umbrella type generator locates the thrust bearing on the bottom side of the

rotor with a guide bearing both top and bottom.

The purpose of the thrust bearing is to provide axial static and dynamic support of the

unit. Performance and reliability related components of a generator thrust bearing consist

of the thrust pot configuration, oil baffles, oil with specification, bearing adjustment

hardware, and coolers. While there are numerous bearing designs, the basic performance

of the thrust bearing is the same. Figures 7 and 8 illustrate common designs. Figure 9

provides a comparison of variant designs. Basic theory is well developed and the


Rev. 1.0, 12/20/2011 222

Kingsbury type bearing is typically a preferred design so it will be used for the following

discussion.

Figure 7: Typical Thrust Bearing Assembly

Figure 8: Typical Thrust Bearing


Rev. 1.0, 12/20/2011 223

C = pad center

Pivot

Pad

E = Eccentricity

Runnerrotation

Figure 9: Thrust Bearing Variations

A rotating collar (runner) and stationary pivoting shoes in a bath of lubricating oil are the

vital elements of the Kingsbury bearing. The development of an oil film with sufficient

thickness and pressure is necessary to prevent contact of the bearing surfaces. The oil is

Leadingedge

Leadingedge

Leadingedge

Babbit

Babbit

Babbit

Trailingedge

Pad

Pad

Pad

Support disk

Support disk

Pivot

Pivot

Runner

Runner

Runner

Cavity

Cavity

E = Eccentricity

Helical spring

Stop block

X - X tangential section




Rev. 1.0, 12/20/2011 224

drawn between the shoes and the runner in operation, possible because the shoes are

pivoted and free to tilt, forming an oil wedge with the required load carrying capacity.

The thrust bearing shoes are babbitt surfaced segmental elements (usually 6 to 8 each)

with hardened pivotal shoe supports on the backside that transmit the load to the housing.

This load is distributed between the shoes either by manual adjustment or automatically

by equalizers. In the Kingsbury design an adjusting screw contacts the support disk and

allows for adjustment to load the bearing and compensate for misalignment. The shoes

are usually instrumented for temperature monitoring.

The thrust bearing bracket connects the thrust pot to the powerhouse. The addition of a

static oil pressurization system, commonly called lift oil, is one of the ways babbitt to

runner contact is eliminated on a unit start before relative motion can establish the

hydrodynamic film. This eliminates a contact of these surfaces during start of the unit.

The structural component of the thrust pot is necessary to circulate the oil in a pattern

through the thrust and guide bearing. The cold oil from the thrust pot cooler must be

supplied to the bearing and then the warm oil returned to the cooler. The thrust and guide

bearing oil system is designed for specific ISO oil with associated properties. The

Bearing OEM oil specification should be considered a requirement for the system. A

filtration system will assist in the removal of debris and water.

The coolers are typically helically coiled, configured around the thrust pot and

submerged in oil to a design level. The coolers must remove the heat load from the thrust

and guide bearing and maintain the design circulating path. Coolers external to the thrust

pot have also been employed.

Except for very minor rotational friction losses the thrust bearing is basically a non-

performance but reliability related component. Additional thrust and guide bearing details

can be found in the turbine BPs.

Guide Bearing and Cooling System: The guide bearing provides support for radial load.

Both pivoted and sleeve type bearings, as shown in Figure 10, are common and in more

modern designs sleeves are adjustable similar to the thrust bearing shoes. The guide shoe

or sleeve is manufactured from forged steel with a babbitted contact surface. The sleeve

designs have structural castings typically in halves with babbitted sleeve surfaces. Guide

bearings are usually instrumented for temperature measurement.


Rev. 1.0, 12/20/2011 225

Figure 10: Guide Bearing Types

A guide bearing may be located at elevations above or below the thrust pot to provide

additional radial support for the shaft.

Guide bearing hardware is a combination of elements that make the connection to the

thrust pot structure for guide bearings integral with the thrust pot. In the adjustable

design the adjusting screw contacts the back of the shoe and allows for adjusting the gap

between the shoe and journal. In the sleeve design the cast sleeve is typically shimmed

into bracket housing.

Except for very minor rotational friction losses the guide bearing is a non- performance

but reliability related component. Additional guide bearing detail can be found in the

turbine BPs.

Generator Shaft: The primary function of the shaft is to transmit the torque delivered by

the turbine to rotate the generator rotor so that this power may be converted to electrical

Rotataion

Rotation


Rev. 1.0, 12/20/2011 226

energy. The Generator Shaft must effectively make all the mechanical connections for

the various attached components and carry all loads without unacceptable vibration. The

operational torque (power input) to the shaft, rotating components dead weight, turbine

unbalanced hydraulic thrust and the unbalanced magnetic pull of the generator must be

structurally carried by the generator shaft.

Shafts may be a single piece manufactured from forged steel but some of large shafts can

be fabricated.

The connection of the turbine shaft to the generator shaft is made with a bolted

connection. Alignment/fitting up of the generator and turbine shafts, attachments and

assemblies is necessary to create and maintain air gap, turbine clearances and bearing

loading.

Generator shaft hardware is typically a combination of studs/bolts/keys and dowels that

make the assembly and their connection to the generator shaft.

Also it should be noted the generator shaft may have a rotating exciter mounted on top of

the generator rotor which provides excitation current and voltage to the field poles.

Typically a Permanent Magnet Generator (PMG) is attached to the top of the rotating

exciter. The details refer to Exciter Best Practice.

The generator shaft is a non-performance but a reliability related component of the

generator.

Generator Rotor: The primary function of generator rotor is to carry the field poles

necessary for excitation of the stator winding. The generator rotor must effectively

make all the mechanical connections for the various attached components and carry all

loads without creating unacceptable vibration. The operational torque (power input) to

the rotor, centrifugal loads created by the mass of the rotor components and other rotating

components (dead weight, rim shrink), and the unbalanced magnetic pull of the generator

must be structurally carried by the generator rotor.

The structural part of the rotor assembly is typically a cast structure, sometimes called a

spider, machined to allow bolting/keying to the generator shaft at the center and the rotor

rim to be installed on the arms with keys.

The rotor rim assembly is a laminated cylindrical structure that stacks on a horizontal

machined surface at the end of the spider arm. The rim is typically shrunk on shrink keys

that that may also transmit the operational torque to the generator. The poles consist of

copper windings that are electrically insulated between turns and establish the electrical

circuit which provides the rotor flux for the air gap. Excitation current is provided to the

field poles by the field leads mounted on the rotor arm which are electrically and

mechanically connect to the collector (slip) rings. The field poles are electrically

connected in series. Figure 11 shows typical field poles mounted on the rotor.


Rev. 1.0, 12/20/2011 227

Figure 11: Typical Field Poles/Rotor Spider

The field poles and electrical connections are the primary performance related

components of the rotor with the balance being non-performance structural components.


1.2.1 Performance/Efficiency & Capability – Oriented Best Practices

The most significant improvement in efficiency and output of the generator may

be realized by a stator rewind to an epoxy based system rated class F. Lower

loss windings with increased copper cross-sectional area and improved

insulating materials will increase the life of the unit. This is due to a better heat

transfer and higher temperature tolerance. This will provide higher output if

input power is available from the turbine and temperature limits are not

exceeded. Any evaluation to uprate the unit by rewinding must also consider the

generator structural components, including the core, to ensure that these

components can withstand the additional torques and stresses associated with the

increase in power.

Provide clear temperature limits to operating personnel and/or for automatic

control system programs for setting alarm (i.e., trip temperatures) for the

generator.


Rev. 1.0, 12/20/2011 228

Trending of stator, field and hot/cold air temperatures will establish accurate

performance of current generator cooling system. Limited IEEE 115 test can

provide high quality data and establish the CPL parameters.

Stator winding temperature limits should be continually monitored. Any trends

indicating increased operating temperatures for the same load and ambient

conditions should be investigated for issues with the cooling system.

Periodic comparison of the CPL to the IPL to detect and mitigate degradation

that may impact efficiency or capacity.

Periodic comparison of the CPL to the PPL to trigger feasibility studies for

major upgrades.

1.2.2 Reliability/Operations & Maintenance Oriented Best Practices

Monitor generator temperatures under operating conditions of load and cooling.

Increasing temperatures under these conditions may be indicative of dirt and

dust contamination. Dust and dirt will impede heat transfer characteristics,

block cooling flow passages, and degrade electrical insulation. Cleaning of

generator windings and air slots to remove oil, dirt, and debris will improve the

heat transfer coefficient of those components. Cleaning of the core slots in

machines with an unusually large amount of blockage may result in

improvements of 5°C to 10°C. The preferred cleaning method is to vacuum

rather than to blow debris unless it is reasonably assured that the dislodged

debris will not simply be relocated in the unit. Dry compressed air may be used

in areas not accessible to vacuum cleaning. Oil and other solvent based

contaminates will attract and capture dirt and debris and should be removed by

approved solvent cleaning, and the source of the contamination, i.e. oil leak,

should be repaired.

The generator air cooler tubes require periodic cleaning to maintain acceptable

heat transfer performance. A major problem in generator air cooler manufacture

was the baffles that created an effective heat transfer flow path for the RCW

becoming totally degraded or lost, resulting in a heat exchanger with poor

performance. Repairs to the coolers may correct some of the problems with

degraded coolers.

A reduction in the air temperature of the generator air cooler by 5°C is common

by cleaning fouled coolers. Efficient coolers will have a cold air discharge

temperature of approximately 5°C above the RCW inlet temperature. In the

case of badly fouled tubes and degraded fins, the air discharge temperature may

be 15°C to 20°C higher than the RCW.

RCW strainer performance is typically judged by the differential pressure across

the strainer which is improved by a well-designed back flush system that

maintains design RCW flow rates.


Rev. 1.0, 12/20/2011 229

The use of proportioning valves may limit thermal cycling of the generator

based on cold air temperature. .

RCW piping leaks due to wall corrosion will degrade cooling system

performance. Leaks of this nature are generally corrected by replacing the

section(s) of pipe affected. Leaks inside the unit air housing should be corrected

promptly to prevent water contamination of electrical or structural components

in the housing.

While overall age is a factor, units cycled frequently are subject to increased

thermal stresses that ultimately affect total generation. Likewise, units operated

outside their capability curves by exceeding recommended temperatures, will

have increased losses, reduced time to failure, and consequently reduced total

generation. Cyclic operations and operations outside the recommended limits

should be minimized.

Shaft vibration should be monitored. Levels of shaft vibration that reach alarm

or trip levels will obviously impact operations, and maintenance will be required

in this case. IEEE 492 Section 7.9 addresses ―Vibration Detection and

Correction‖. Acceptable vibration and Shaft Run out are indicated in Section

8.3.7.1 and it is noted ―No standards for acceptable maximum vibration have

been developed ―. This is partly due to the fact that there are numerous machine

designs with different generator thrust and guide bearings and likewise for the

turbine guide bearings. Develop root cause of vibration problems and schedule

maintenance repairs or modification.

Monitor bearing temperatures to alarm and trip when recommended temperature

limits are exceeded. Multiple shoes of each bearing should be monitored to

preclude the possibility of a single failed temperature detector allowing an

undetected bearing over temperature event.


I&C - Automation

Mechanical - Francis Turbine

Mechanical – Kaplan Turbine

Mechanical – Pelton Turbine

Electrical - Exciter



The underlying technology of generators has not changed appreciably since the 1900‘s. The

basic principal of a rotating flux produced by a DC current circulating in the rotor and


Rev. 1.0, 12/20/2011 230

generating an AC voltage is unchanged. Improved materials as well as enhanced monitoring,

assessment and design tools have facilitated improved reliability and efficiency.

Generator shafts were typically manufactured from a forging with a material similar to

ASME 668 as a single piece shaft. Early casting technology limited the economic diameter of

the shafts to around 36 inches. As technology developed, larger diameter and better quality of

shafts were possible allowing integral thrust runners. Thrust runners from the early 1900‘s

were often cast iron which was difficult to modify due to porosity slightly below the runner

surface.

Generator rotors from the 1930s to 1970s were designed with significant margin for

operational torque (input turbine horsepower) by the generator OEM. Thus the rotor may

readily be rehabilitated and be adequate for increased capacity without replacement. The

design fatigue life of the generator rotor will be established by material condition and loads.

The first part of the 1900‘s, generators were open air cooled machines that utilized ambient

air for the cooling system from the powerhouse area. This cooling system resulted in high

operating temperatures due to some amount of recirculated cooling air and possible high

ambient air temperature. By the 1930‘s most designs utilized enclosed air housings with air

coolers that utilized RCW heat exchangers as the heat sink.

Electrical insulation technology has seen improvements that allow for longer life and

operation at higher temperatures, with higher reliability, and equivalent insulation levels with

less material (i.e. thinner ground wall). Early units were likely to use an asphalt or bitumen

varnish with mica tape insulating system for the stator winding. Current technology still

utilizes a mica tape but with a synthetic epoxy or polyester resin as a binder. Insulation

classes as defined by National Electrical Manufacturers Association (NEMA) establish the

operating temperature limits for each ―class‖ of insulation.

Performance levels for the generator can be stated at three levels as follows:

The Installed Performance Level (IPL) is defined by the unit performance

characteristics at the time of commissioning. For the generator this is primarily

related to guaranteed losses, as provided by the manufacturer and measured to the

extent possible during performance testing.


performance characteristics as determined by unit efficiency testing.

The Potential Performance Level (PPL) typically requires reference and comparison

of the IPL (and CPL) to design data for a new unit.


A typical generator will have an efficiency of about 96.5%. Approximately 2.5% of the

losses must be removed from the machine by the cooling system to provide adequate cooling.

Table 1 shows losses associated with a rotating exciter that are not necessarily influenced by

the cooling system due to the location of the excitation components. Improvements in the


Rev. 1.0, 12/20/2011 231

losses of the ventilation system normally have little impact on total losses or machine

efficiency (less than 0.01 %). In this document, ―I‖ represents the magnitude of the current

which is load dependent; and ―R‖ represents the value of the resistance which is a function of

material properties and temperature.

Table 1: Typical Generator Losses for Various Manufacturers

The most significant improvement in efficiency and output of the generator (PPL) may be

realized by a stator and rotor rewind to an epoxy based system rated class F. Lower loss

windings with increased copper cross-sectional area and improved insulating materials with

better heat transfer and higher temperature tolerance will increase the life of the unit and

provide higher output. Low loss steel core laminations will reduce core losses. Any

evaluation to uprate the unit by rewinding must also consider the generator structural

components, including the core, frame and rotor to ensure that these components can

withstand the additional torques and stresses associated with the increase in power.

Increasing air flow can improve life expectancy or MVA rating. Figure 12 illustrates the

effect of increased air flow, the attendant drop in temperature and the projected increase in

life. An approximate rule is that electrical insulation life is decreased by one-half for each 10

degree C rise above the rated value for that insulation class. Improvement of generator

cooling system performance may be achieved by increasing air flow and use of generator air

coolers with improved heat transfer characteristics. A new fan and baffle design may also

increase air flow. Also rerouting the air flow to utilize the rotor spider to develop increased

air static pressure at discharge from the fan blades may also be possible. Material selection

for tubing in generator air coolers has tended to be 90/10 Copper Nickel. However, any

material selection should include site water chemistry analyses to identify the presence of

chemical or biological attack on the tubes, heads, and baffles (wetted parts).

Generator Rating,

kVA 30,000 31,250 35,000 33,080

Vintage 1940 1951 1941 2009

Basis

rated load and .9

p.f.

rated load and

.8 p.f.

rated load

and .9 p.f.

rated load

and .9 p.f.

Voltage, kV 13.80 13.80 13.80 6.90

Losses in kW

%, Average

Field I2R 200 128 162 262 0.3

Collector Brush Contact 2 2 1.7 1 0.0

Exciter and Exciter

Rheostat 41 22 28.5 25 0.1

Friction and Windage 120 135 170 50 0.4

Core 250 185 195 81 0.7

Armature I2R 156 140 184 197 0.5

Stray Load 148 95 131 39 0.4

Total 917 707 872.2 655


Rev. 1.0, 12/20/2011 232

60

65

70

75

80

85

90

95

100

80 100 120 140 160 180 200 220

Tem

pe

ratu

re (

C

)

Air Flow (%)

145 MVA 130 MVA

115 MVA 100 MVA

13

20

40

5

10

1

2

3

Year

Stainless steel piping such as ASTM A312 has been successfully used, but the use of ASTM

105 or similar carbon steel piping has been proven to enhance durability and lifespan.

Figure 12: Typical Life Improvement Based on Airflow



The generator system condition is largely a function of its age, the way it has been

maintained, the way it has been operated, and the adequacy of its design. Generator losses

can often be attributed to the machine design and the materials used in its construction. The

impact of the ventilation system on losses is most often seen in the change in resistance of

the copper at different temperatures. While this change is typically small and the resistances

are very small, it does have a calculated effect on losses. A thorough condition assessment of

all the generator components will be difficult without an outage and some level of

disassembly. Various test and maintenance inspections and on-line monitoring can provide a

reasonable condition assessment of the generator. While overall age is a factor, units that are

cycled frequently are subject to increased thermal stresses that contribute significantly to a

deteriorated condition that ultimately affects total generation. Likewise, units operated

outside their capability curves by exceeding recommended temperatures, will have increased

losses, reduced time to failure, and consequently reduced total generation.


Rev. 1.0, 12/20/2011 233

The design and capacity of the system should match the operational requirements, i.e. turbine

input power. The generator rating should be adequate for the available turbine power.

The RCW Motor Operated Isolation Valve opens when a unit starts and closes when a unit

stops. The motor and valve condition can largely established by operation history and age.

The RCW pump and motor is normally a centrifugal pump with an induction motor.

Developed pressure across the pump with rated flow (from a RCW flow meter) is usually

sufficient to determine if the pump is operating acceptably. The RCW strainer condition can

be evaluated based on pressure differential across the strainer and its performance after a

back flush to operate at rated pressure drop or lower.

RCW pipe is difficult to evaluate for wall thickness due to fouling on the inside of the pipe

that may be ½ to ¾ of an inch on 6-8‖ pipe. Pinhole leaks may ultimately develop along the

length of the piping system so replacement is typically justified.

The manual valves can be operated to determine if it is properly operated. Condition of disc,

seats and other internal components would require removal from the pipe connections. Age is

the major factor in the manual valve‘s life.

RCW cooling systems instrumentation should be routinely checked for accuracy, especially

air cooler thermocouples/resistance temperature detectors (rtd‘s), pressure gages and flow

meters. Some temperatures can be checked with hand held pyrometers or thermal imaging

equipment, depending on the accessibility. Instrumentation accuracy is subject to

deterioration due to corrosion, loose connections, electrical deterioration, obstructed or

blocked flow passages or mechanical damage.

Generator air cooler condition can be evaluated by checking cold air temperature variations

in the vertical and horizontal directions across the face of the cooler and the overall

temperature drop/rise of the coolants. Significant variations across the horizontal and vertical

dimensions (> 8° F) may be due to air gap problems or localized hot spots in the armature.

Fins should be inspected for contact with the tubes. It is possible to check air pressure drop

across the coolers depending on the accessibility. Degradation/loss of generator air cooler

head baffles will result in poor cooling efficiency and cold air temperatures that are 20°C

above the RCW temperature.

Condition of the proportioning valves can be readily determined as to whether the valves are

adjusting water flow for the variations in air temperature.

The generator fan blades are fabricated assemblies that are typically attached to the top and

bottom of the rotor rim. Inspections can identify fatigue cracks, defective welds, loose

hardware or mechanical damage that may impact cooling.

Although the system stator‘s electrical insulation integrity has no correlation with losses, it is

important to note that insulation failure will result in lost generation. Insulation integrity is

reduced with age increasing. Increased age exposes insulation to the cumulative effects of

thermal stress and cycling, vibration and mechanical damage, and deleterious contaminates.

A variety of electrical tests may be performed to aid in assessing insulation condition, and the

majority of accepted industrial techniques for generator condition assessment are associated


Rev. 1.0, 12/20/2011 234

with testing and monitoring of the insulation system. A number of these tests and techniques

are identified in Information Sources [10 and 17].

The generator rotor can be inspected on a periodic basis for loose hardware, pole

overheating, pole electrical connection integrity, air gap, rotor roundness, loose fans, loose

shrink keys, brake ring heating or deformation. Structural components can be non

destructively examined (NDE) for cracks or failures. During operation, vibration should be

trended, and apparent causes for excessive levels of vibration include eccentricity between

the rotor and stator, bearing issues, air gap anomalies, or alignment. While no standards

identify acceptable levels of vibration, IEEE 492 addresses ―Vibration Detection and

Correction‖. Trip and alarm setpoints for a specific unit should be established by the

Original Equipment Manufacturer (OEM) or by operating experience.

The condition assessment of the oil lubricated thrust and guide bearing includes vibration

measurements and temperature of the bearing in operation. Abnormal indications could be a

sign of failure of the babbitted surface (wipe), un-bonding of the babbitt from the bearing

shoe, or contamination of the oil which can be established by oil sample analyses.

3.2 Operations

It is recognized that the rating of the generator may not be matched to the load capability of

the turbine. However, loading of the generator should be maintained within the

manufacturer‘s capability curve.

Stator and rotor winding temperature limits are based on NEMA insulation class, and should

be continually monitored. Any trends indicating increased operating temperatures under the

same load and ambient conditions should be investigated for issues with the cooling system.

Output of the unit is limited in the ―overexcited‖ region by the operating temperature of the

field (excitation system) and may be limited by core end heating in the ―under excited‖

region. Generally, measurements of the field and core temperature are collected using

embedded resistance temperature detectors or indirect methods. The limits must be

maintained for rated output of the unit.

It is not unusual for a hydro generator to be operated with failed coils cut out of the winding

path. This is generally done to minimize repair cost and to expedite the return to service

following a coil failure. The manufacturer should be consulted in these cases to determine

deratings and remediation measures required. Any losses associated with this setup can be

restored by replacing the failed coils.

Marginal operational control of a typical generator cooling system is possible due to the

design. One exception is proportioning valves to control RCW flow to the generator air

coolers to maintain a constant hot or cold air temperature. The benefit of the proportioning

valve is in a situation where the generator is operating in load following mode with

significant changes in MVA output. The valve controller would be set to the desired air

temperature.


Rev. 1.0, 12/20/2011 235

The generator rotor should have a significant margin for fatigue failure under design loadings

including design basis transients. Operation at higher MW output may accelerate fatigue

damage of components and should be evaluated by analyses. Also the operation of the

generator at higher MVA and PF conditions may result in high field temperatures that tend to

loosen the shrink of the rim to the rotor arm keys. Operational limits should be imposed for

the generator as a machine with all structures, components and assemblies evaluated.

3.3 Maintenance

A well designed and supported Maintenance Program is essential to the reliability, operation

and maintenance planning for the generator. Maintenance procedures are needed to ensure

that consistent and effective maintenance is performed. These procedures should be based on

manufacturers‘ recommendations and operating experience.

Deterioration of the cooling system effectiveness may be caused by misoperation of heat

exchangers, rotor fans, automatic cooler controls, fouling of stator vents, or ambient

conditions. Any decrease in cooling effectiveness is subject to increased I2R (resistance R by

the current I squared) losses. The generator RCW pipe and generator air cooler tubes foul in

any system. The cleaning of the RCW pipe is probably of minimum value unless the fouling

reduces RCW flow below design value. If design flow rates are not achievable with adequate

pump or head pressure, fouled or obstructed piping may be the cause. Water jet or hydrolaze

cleaning of RCW piping may improve flow rates. The generator air cooler tubes are more

vital and require periodic cleaning to maintain the acceptable performance when indicated by

excessive cold air temperatures. Another potential problem in the older generator air coolers

was the baffles that were designed to create an effective heat transfer path for the RCW.

After years of service, these baffles are totally degraded or lost, resulting in a heat exchanger

with poor performance. Also, the fins may become separated from the tubes which

effectively eliminate the fins surface from heat transfer. Degraded baffles should be repaired

and new gaskets installed on the heads. Degradation of generator air cooler tubes may result

in leaks and water being transported to the stator and field coils. Air cooler cleaning is

typically accomplished by removing the coolers from the generator. The coolers should be

cleaned annually, or even more frequently, if severe fouling occurs. The heads are removed

and the tubes can be cleaned with a tool. In severe cases of unusual biological fouling, it

may be necessary to increase the cleaning frequency. Frequencies may require seasonal

adjustments.

The rotor assembly requires minimum maintenance except to inspect the bolted

connections/keys and correct any loose assemblies, shaft/rotor mating fretting, field leads on

the rotor arm, rim studs, fans blades, and poles. Shrunk on collars should be examined for

fretting of surfaces if access is possible. The tightness of the shrink keys should also be

checked in machines with 30-40 years of service. A re-shrink of the rim may be desirable to

reestablish the compressive load on the rotor arms and ensure acceptable contact between the

rim/pole assembly and the arm key. NDE examinations of structural welds and attachments

should be conducted on a periodic basis. The maintenance procedure should include the

periodic measurement of rotor air gap data. The reduced air gap may be due to frame/core

movement, rotor rim issues or pole mounting issues. The interpole electrical connections


Rev. 1.0, 12/20/2011 236

(including amortisseur windings) should also be checked for indication of overheating or

mechanical failure or damage.

The stator bolted connections in the phase and neutral lead assembly should be checked and

tightened either during outage or checked indirectly by temperature measurement during

operation. Minor I2R losses may be seen here if connections have deteriorated or been made

improperly. Generator inspections and testing should be performed periodically by

individuals‘ knowledgeable in generator design, operations and maintenance. Generator

reliability is highly dependent on the ability to detect and address incipient issues affecting

the integrity of the stator winding.

As seen in Table 1, the collector ring and brush assemblies often account for small losses

(excitation system). To minimize these losses, operators should follow the manufacturers‘

recommendations relative to collector rings and brush rigging. The brush dust generated by

the collector ring and commutator brushes (if present) makes this a high maintenance area.

Lack of attention in this area can result in a flashover due to the low resistance tracking paths

caused by the brush dust.

Perform NDE on stator structural frame welds during major outages or as indicated by

operating experience.

Generator Neutral Grounding Systems traditionally are constructed using distribution

transformers, resistors, and/or inductors. Contamination may cause tracking during fault

conditions resulting in higher fault current for a line to ground fault, which could in turn

result in more damage to the generator iron. Other components associated with the neutral

grounding system include breakers and disconnect, which should be visually inspected. Oil

filled breakers or grounding inductors/transformers should be checked for leakage. Cleaning

and testing is recommended on a scheduled basis as determined by the manufacturers‘s

recommendations and operating experience.



Reductions in stator operating temperature will reduce the value of R and consequently the

I2R losses. However, the R factor in this equation is minor in comparison to the I

2 factor.

Personnel should also take caution that they must follow the manufacturer‘s operating

temperature guidelines to prevent damaging differential expansions between generator

structural and winding components.

Determination of other losses (e.g., windage and friction, core, stray load, and excitation

system) requires various measurements made during different modes of performance testing

as described in IEEE 115 [10]. These losses are originally calculated and provided by the

manufacturer, but the cost of retesting to determine any deterioration or improvement should

be compared to the potential expected benefit.

The largest losses in the generator are the I2R losses in the stator and rotor. An

approximation of these losses can be calculated and compared to design values in an effort to


Rev. 1.0, 12/20/2011 237

determine the gap between the IPL and CPL. Accurate resistance measurements of

components subject to I2R losses at a reference temperature are required. Methods of

temperature determination include thermometer methods, embedded detector methods,

coolant temperature measurements, and indirect measurement with scanning devices.

Voltage and current measurements are also required to determine resistance at operating

temperature. Loss in watts is calculated by multiplying the resistance R by the current I

squared, or I2R.

Resistance at a given operating temperature may be calculated by comparing the measured

resistance of the winding (or rheostat) at a known temperature as follows: [10]

Rs=Rt((ts+k)/(tt+k))

Where:

Rs is the winding resistance, corrected to a specified temperature, ts, in ohms;

ts, is the specified temperature in degrees Celsius;

Rt is the test value of the winding resistance, in ohms;

tt is the temperature of the winding when resistance was measured, in degrees

Celsius;

K is 234.5 for copper, 225 for aluminum, in degrees Celsius.

It should be noted that the values for the ―Limiting observable temperature rises of indirectly

cooled salient-pole synchronous generators and generator/motors for hydraulic turbine

applications ―are given in Table 6 of ANSI C50.12. Note the allowable observable

temperature rise for Class B insulation is 85 degrees C, and for Class F insulation is 105

degrees C based on an ambient temperature of 40 degrees C.

Generator shaft vibration is a measure of performance and reliability. Vibration

measurements may include shaft displacement (x and y) at selected elevations along the axis

of the shaft. A vibration monitoring system should be installed with unit alarm and trip

values set based on operating experience and manufacturers‘ recommendations.

4.2 Data Analysis

Generator IEEE 115 test data is typically evaluated against the IPL test data and

manufacturers calculated data. It is typically very difficult to obtain test data at the rated

MVA, KV and PF conditions. Therefore, the test losses at lower ratings are extrapolated to

the machine rated values.

Trend analysis of bearing temperatures, generator vibrations and oil sample data will be

necessary to reasonably establish the bearing CPL. These analyses should compare results to

previous or test data from commissioning of the unit (IPL). This data can be compared to

OEM data if available for bearing losses, operating temperatures and potential failures.


Rev. 1.0, 12/20/2011 238


The use of periodic IEEE 115 test may be used to update the unit operating characteristics

and limits. This also provides data to evaluate the stator/rotor condition. Optimally the heat

run data obtained would be integrated into an automatic system (e.g., Automatic Generation

Control), but if not, hard copies of the curves and limits should be made available to all

involved personnel.


Baseline Knowledge:

Liwschitz-Garik, M., Whipple C., Electric Machinery Vol.1 Fundamentals and D.C.

Machines - Third Printing July 1947

Chapman, Alan J., Heat Transfer - Third Edition, Macmillan Publishing 1974

Buffalo Forge Company, Fan Engineering - Eighth Edition 1983

Walker, John, Large Synchronous Machines Design Manufacture and Operation -

Clarendon Press Oxford 1981

TVA, Design of Projects Technical Report No. 24 Electrical Design of Hydro Plants

Electric Power Research Institute, Handbook to Assess the Insulation Condition of Large

Rotating Machines, EPRI EL-5036, Volume 16, June 1989.

State of the Art:

Sumereder, C., Muhr, M., Korbler, B., Life Time Management of Power Transformers - Graz

University of Technology – Austria TUG Sumereder A1 Session 1, Paper No. 35-1

Fenwick, G.T., Generator Air Cooler Design and Selection for Optimum Performance,

Upgrading and Refurbishing Hydro Plants - Unifin Corporation October 29,1991

Lehoczky, K. N., Generator Life Expectancy Extension and Increased MVA Output through

Three-Dimensional Cooling Design - HydroVision 94 Conference, Phoenix, Arizona.

Standards:

IEEE 115, Guide, Test Procedures for Synchronous Machines

IEC 32, Part 2 International Electro Technical Commission Methods of Determining Losses

and Efficiency Of Rotating Electrical Machinery from Test (Excluding Machines for

Traction Vehicles) Measurement of Losses by the Calorimetric Method

ANSI C50.10 American National Standard: Rotating Electrical Machinery - Synchronous

Machines

ANSI, C50.12 – IEEE Standard for Salient-Pole 50Hz and 60 Hz Synchronous Generators

and Generator/Motors for Hydraulic Turbine Applications Rated 5 MVA and Above


Rev. 1.0, 12/20/2011 239

IEEE, 1 - Recommended Practice — General Principles for Temperature Limits in the Rating

of Electrical Equipment and for the Evaluation of Electrical Insulation

IEEE, STD 492 Guide for Operation and Maintenance of Hydro-Generators

ANSI/IEEE Std 1010-1987 An American National Standard IEEE Guide for Control of

Hydroelectric Power Plants

Recommended Practice for Testing Insulation Resistance of Rotating Machinery, IEEE Std

43, 2000.

American National Standard for Rotating Electrical Machinery - Synchronous Machines,

ANSI C50.10.

ISO 7919 Mechanical Vibrations on Non Reciprocating Machines Measurements on Rotating

Shafts and Evaluation Part 5 Guidelines for Hydraulic Machine Sets

ORNL et al, HAP Condition Assessment Manual, October, 2011

IEEE, STD C62.92.2, Guide for the Application of Neutral Grounding in Electric Utility

Systems : Part II – Grounding of Synchronous Generator Systems


Main Power Transformer

Revision 1.0, 12/08/2011

HAP – Best Practice Catalog – Main Power Transformer

Rev. 1.0, 12/08/2011 241



1.1.1 Main Power Transformer Components .................................................................... 242


1.2.1 Performance / Efficiency & Capability - Oriented Best Practices ........................... 244

1.2.2 Reliability / Operations & Maintenance - Oriented Best Practices .......................... 244







3.2 Operations .................................................................................................................... 250

3.3 Maintenance ................................................................................................................. 251



4.2 Integrate Improvements................................................................................................ 255



Rev. 1.0, 12/08/2011 242


This best practice for the Main Power Transformer (MPT) discusses design components,

condition assessment, operations, and maintenance best practices with the objective to maximize

overall plant performance and reliability.

The primary purpose of the main power transformer is to step up the generator output to a higher

voltage for efficient transmission of energy. The MPT is a critical component of any generation

station. As the MPT connects the generator to the transmission grid, the output of the generator is

directly dependent on the availability and operational status of the transformer. Thermal and

electrical limits of the transformer must be considered in the plant operation. Proper design,

operation, and maintenance are required to provide the utmost efficiency, performance and

reliability of the hydro unit.


Hydropower Facility → Powerhouse → Power Train Equipment → Transformer

1.1.1 Main Power Transformer Components

The components of the MPT related to performance and reliability consist of a core,

windings, dielectric insulation system, bushings, and external cooling system.

Core: The core functions to provide an optimal path for the magnetic flux and

efficiently magnetically couple the windings. The core of a transformer is comprised

of thin magnetic laminations stacked together and tightly clamped into place by a

steel clamping structure. Cores can be designed as either single phase or three phase

configurations depending on capacity and user requirements.

Windings: The windings function as the conducting circuit for the transformer and

consist of turns of insulated wire or cable which are placed around the magnetic core.

A primary and a secondary winding are used in a typical two-winding MPT. The

alternating current that flows through the primary winding establishes a time-varying

magnetic flux, some of which links to the secondary winding and induces a voltage

across it. The magnitude of this voltage is proportional to the ratio of the number of

turns on the primary winding to the number of turns on the secondary winding. This

is known as the ―turns ratio.‖ By operating at higher voltages electric power can be

transmitted more efficiently.

Dielectric Insulation System: The electric insulation system consists of both solid

and liquid dielectric materials. The purpose of this system is to insure that the

windings, conductors, and core remain electrically insulated from one another and

from ground potential. The solid dielectric insulation system consists of various

materials including electrical grade cellulose, Nomex®, pressboard, wood, and

insulating varnishes and films. The liquid insulation consists of an insulating fluid,

normally a highly processed mineral oil, which provides the dielectric properties

required as well as serving as the cooling medium for the transformer.


Rev. 1.0, 12/08/2011 243

Bushings: The function of the bushings is to provide a path for current flow from the

windings inside the transformer to external connections while maintaining the

dielectric integrity of the voltage-to-ground clearance required. A central conductor

passes through an insulator which can consist of porcelain, resin, or polymer material.

The inside of the bushing may contain paper and foil layers, film, or ink to create a

low value capacitance to grade the voltage between the conductor and ground. These

bushings are usually filled with insulating oil and are known as capacitor type

bushings. Lower voltage bushings may consist of only a central conductor and an

insulator.

External Cooling System: The purpose of the external cooling system is to remove

the heat generated by power losses within the transformers and maintain operation

within design temperature parameters. The removal of heat protects the windings,

core, and dielectric system from thermal degradation. The external cooling system

can be comprised of radiators, coolers, fans, motor driven pumps, and/or water cooled

heat exchangers based on the design and capacity requirements of the transformer.

Non-performance, but reliability related components of a MPT include the tank, oil

preservation system, and controls/protective devices.

Tank: The purpose of the tank is to provide a sealed container to house the core,

winding assembly and the insulating fluid. The tank is usually made of welded steel

construction and is provided with removable inspection covers. The bushings are

mounted to the tank for electrical connection to the transformer windings. Auxiliary

equipment such as controls, protective devices, and cooling systems are usually

attached to the tank.

Oil Preservation System: The purpose of the oil preservation system is to prevent

moisture, atmospheric air, and other contaminates from entering into the tank and

contaminating the insulating system. This minimizes oxidation and deterioration of

the dielectric insulation system both chemically and electrically. There are various

types of oil preservation systems including gas sealed, pressurized inert gas sealed,

free breathing, and sealed conservator type systems.

Controls/Protective Devices: The purpose of the controls is to provide for operation

and protection of the auxiliary equipment required for the transformer.

Instrumentation is also part of the control system. They provide for manual and

automatic control of the equipment, monitoring of temperatures, trip and alarm

functions, and power supply transfers. The controls are usually housed in a cabinet

mounted to the transformer. The protective devices can vary based on the user’s

specifications and include such items as pressure relief devices, rapid rise fault

pressure relays, temperature indicators, and lock out systems for tap changers.


Rev. 1.0, 12/08/2011 244


1.2.1 Performance / Efficiency & Capability - Oriented Best Practices

Routine testing to verify performance within the original design criteria and

factory test baseline data.

Real-time monitoring and analysis of transformer performance at Current

Performance Level (CPL) to detect and mitigate deviations from design

parameters for the Installed Performance Level (IPL) due to system degradation,

thermal issues, or malfunction of instrumentation.


trigger feasibility studies of major upgrades or replacement opportunities.

Maintain documentation of IPL and update if major modifications are performed

(e.g., winding replacement, cooling system upgrades, oil reclamation).

Periodic comparison of the CPL to the IPL to monitor deterioration and trigger

maintenance or repair. This is especially important regarding routine field

electrical test results.

Trend transformer performance and test data for early detection of deterioration,

contamination, thermal degradation, and incipient faults.

Include industry acknowledged choices and experience for transformer design,

replacement components, and maintenance practices to plant engineering

standards.

1.2.2 Reliability / Operations & Maintenance - Oriented Best Practices

Establish a comprehensive dissolved gas-in-oil analysis (DGA) testing program to

monitor the internal health of the transformer. Accurate analysis and trending of

analytical data can provide early detection of thermal and electrical incipient

faults and allow for intervention and mitigation measures.

Maintain an insulating oil quality testing program to monitor the chemical and

electrical condition of the insulating fluid. Degradation of the insulating fluid

leads to degradation of the solid insulation system which can lead to failure. The

life of the insulation system is the life of the transformer.

Implement a routine electrical testing program and track and trend critical data.

Establish action limits to correct defects found prior to placing the transformer

back in-service.

Insure operation of the MPT within its design voltage limits, typically 105%

maximum to avoid damaging over-excitation issues. Adequate voltage taps should

be provided to adjust to any feasible system condition to prevent this situation.

Operate the transformer within its thermal design limits to prevent accelerated

thermal aging and damage to the insulation system and bushings.


Rev. 1.0, 12/08/2011 245

Investigate all oil or nitrogen leaks and determine the need and priority for repair.

Maintain the cooling and oil preservation system with a preventative maintenance

program as these systems protect the transformer from damaging heat, moisture,

and atmospheric air.

Trend bushing condition and replace when significant deterioration is indicated by

comparing all test values to individual bushing nameplate data.

Recondition or reclaim insulating oil when trend analysis indicates need.

Test and calibrate controls and indicating devices and upgrade when required.

Insure availability of on-site or system wide spare transformer(s) and spare parts

to reduce the forced outage time incurred with a failure.

Monitor for trends of deteriorating condition of the transformer (decrease in

Condition Indicator (CI)) and decrease in reliability (an increase in Equivalent

Forced Outage Rate (EFOR), a decrease in Effective Availability Factor (EAF).






Transformers have changed very little since their inception with regard to their functionality.

The principal change is the efficiency and performance of modern core designs and improved

windings and insulation materials. Modern transformers are smaller, have higher thermal

limits and fewer losses than the older transformer fleet. Advancements in core materials,

winding design and maintenance innovations have improved efficiency and reliability

significantly.

Performance levels for MPT designs can be stated at three levels as follows:

The Installed Performance Level (IPL) is described by the transformers performance

characteristics at the time of installation. These may be determined from factory

reports and baseline field test comparisons performed prior to initially placing the

transformer in-service.

The Current Performance Level (CPL) is determined by an accurate analysis of the

transformers operating characteristics. These would include thermal performance at

full load as well as component condition or test deviations discovered.


Rev. 1.0, 12/08/2011 246

Determination of the Potential Performance Level (PPL) typically requires interface

with vendors for new transformer design, loss information, and cost in order to

evaluate the achievable performance potential of replacement transformer(s).

Transformer efficiency is primarily determined by the original design criteria. Incremental

efficiency improvements may be accomplished by system upgrades, but winding and core

replacement are often not cost effective for very old transformers. The transformers

insulation condition and age are among the top factors in an assessment to determine whether

the MPT is a candidate for replacement or rehabilitation.

Analysis of operational history and test data may indicate that the CPL has significantly

deviated from the IPL. Increased maintenance and operational constraints are also used to

determine the CPL.

Many older transformers were more liberally designed and losses were not evaluated as

critically as today. These losses can be significantly higher than those of a modern

transformer. Losses associated with the MPT can be grouped into three major categories.

Load losses

No-load losses

Auxiliary losses

The load losses are the largest of the three followed by the no-load losses. The auxiliary

losses are comparatively quite small. For example, typical losses for a 36 year old MPT rated

161-13.2-kV, 58,500/78,000/87,300 kva, three phase, 55oC/65

oC rise, ONAN/ONAF are:

Load losses 212.57 kW at rated current

No-load losses 56.07 kW at 100% rated voltage

Auxiliary losses 3 kW with all fans in operation

The load losses are associated with the windings and primarily consist of:

I2R loss associated with current

Eddy current loss in the winding conductors

Advanced technology in winding conductor arrangements, transposition, and materials are

used today in modern designs to reduce these losses. As the name implies, these losses are

governed by the load current carried by the transformer and the resistance of the windings.

The no-load losses are associated with the core but independent of the load for the most part,

and they are incurred whenever the transformer is energized. These losses are primarily the

result of:

Excitation current

Hysteresis loss


Rev. 1.0, 12/08/2011 247

Eddy currents

The auxiliary losses are associated primarily with the cooling system and are incurred by the

pump motors and fan motors and are usually negligible in comparison to load and no-load

losses.


More efficient material and manufacturing techniques have been developed over the years to

reduce the no-load losses. Modern transformer designers can utilize various grades of steel

for the core laminations. Fabrication techniques such as laser etching were not available

years ago. Improved core assembly and configuration processes are also utilized in modern

transformers. Figure 1 shows an example of a modern core in a manufacturing facility.

Figure 2 illustrates a 3-phase winding assembly before installation in the tank.

Advancements in instrumentation and controls can now provide for more efficient and

reliable monitoring of the transformer and associated systems. These include fiber optics for

actual winding conductor temperature, bearing wear monitors for motor driven oil pumps,

partial discharge probes, and on-line bushing monitors.

Replacement of aged MPT’s with modern state of the art designs may result in significant

reduction of losses as compared to those of 40-50 year old transformers. The cost savings

should be considered for the life cycle of a new transformer and decisions should not be

based solely on initial costs. Additionally, establishing partnering agreements with

manufacturers and developing standardized designs can result in substantial cost savings in

the purchase cost of replacement transformers and reduce inventory of spare parts.

Figure 22: Modern Core during Manufacturing


Rev. 1.0, 12/08/2011 248

Figure 2: Three Phase Winding Assembly



Once the MPT is properly assembled, oil filled, and energized, its life cycle begins. A

reliable life cycle is determined by how well the MPT is operated, maintained, and protected

from faults. Reliability and loss prevention of the IPL and CPL are directly related to proper

operation and maintenance of the MPT.

In order to provide for a representative condition assessment of the MPT, the first step is

information gathering. Initial data includes: DGA, oil quality, factory tests, routine

electrical tests, thermographic tests, operational history, maintenance history, and fault

history. Component failure and replacement as well as any major upgrades or repairs is

important information to review. Interviews with maintenance personnel can provide

excellent information on current and past issues. Depending of the frequency of test cycles, it

may be useful to review the last 15-20 years of test results and history. The quality of the

data directly relates to the quality of the condition assessment. Trending and analysis of all

data sources are performed to determine past experience and current health of the MTP.

DGA data is one of the most valuable diagnostics for determination of the internal health of

the transformer. Overheating of the oil and cellulose, partial discharge, sparking/arcing, and

decomposition of cellulose materials can be monitored, detected, and trended to reflect

internal reactions occurring within the transformer.

The quality of the oil and its maintenance plays an important part in the life of the insulation

system. Insulating oil degrades in time and the degradation by-products can have a

considerable negative effect on the paper insulation. Accelerated aging and loss of insulation

strength can occur if the oil is not properly maintained. Periodic analysis of the oil quality

tests data detects adverse conditions and allows for planned oil maintenance when required.

Various electrical tests can validate the integrity of the MPT. Insulation power factor tests

can assist in determination of the winding insulation as well as that of the bushings. Winding

resistance tests can detect problems in tap changer contacts, poor connections (bolted or

brazed) and broken conductor strands within the windings. Analysis of electrical test data is


Rev. 1.0, 12/08/2011 249

an important tool to assist in determination of the transformers electrical integrity. Trending

of the test results is invaluable in determining the degree and rate of degradation.

Thermographic inspections and analysis can provide a wealth of information ranging from

low oil levels and overheating in bushings and connections to component malfunction such

as poor heat transfer in radiators and coolers. A thorough review of thermal data provides yet

another tool for condition assessment. Figure 3 is an example of a thermographic image.

Figure 23: Thermographic Image Showing Low Oil Level in HV Bushing

The age of the transformer must be considered as it relates to the condition of the insulation

system. In the presence of heat, moisture, and oxygen, all cellulose insulation systems will

deteriorate. The insulation strength will weaken until the system cannot adequately perform

its intended electrical function. Even with excellent maintenance these three entities can be

minimized, but not entirely eliminated. Replacement of the entire insulation system for a 35-

40 year old transformer is not economically feasible. Age plays an important factor in the

condition assessment of MPT’s.

After or during the data process, a physical inspection of the MPT is necessary in order to

form a current impression of the equipment and discover any existing anomalies. Nameplate

information can be obtained during the inspection. A systematic inspection process for the

condition assessment should be performed to include the main tank, cooling system,

bushings, oil preservation system, tap changer, controls, and protective/indicating devices.

Upon completion of the data assessment and physical inspection, a systematic and consistent

approach should be used for each MPT. This allows some prioritization to be assigned to


Rev. 1.0, 12/08/2011 250

each MPT for ranking purposes which assists in developing a plan for rehabilitation or

replacement options assisting in both short term and long term strategic planning.

3.2 Operations

The MPTs operational parameters are governed by the original design criteria. Operation

within these parameters provides the most efficient performance of the equipment and

provides for optimum service life.

All transformers have thermal limits that must be strictly observed in order to maximize the

life of the transformer. These temperature rise ratings are typically 55oC for standard

cellulose insulation or 65oC for thermally upgraded cellulose. These temperature rise ratings

are based on a 30oC ambient. These ratings also determine the set points for the first and

second stage cooling equipment if provided. Elevated operating temperatures above design

ratings will cause excessive deterioration of the insulation system. For every 10oC increase in

windings hot spot temperature above the design, the solid insulations reliable service life is

cut in half. Thermal decomposition is cumulative and the life of the transformer is the life of

the insulation system.

The MPTs capacity must equal or exceed that of the generator output. This is determined

during design and any anticipated future uprates to the generator need to be considered when

initially sizing the transformer. Sustained overloading can have significantly adverse

consequences and cause damage to the windings, core, and insulation system. Overloading

can also cause excessive temperature rise to occur in sealed bushings and lead to failure. The

MPT should be operated within its design capacity in order to maximize the service life,

The maximum continuous operating voltage as governed by ANSI C84.1-1995 and IEEE

C57.1200 is 105% continuous secondary voltage at rated MVA and at a power factor not less

than 0.8. The system conditions may require tap changer adjustments higher than the system

voltage for regulation purposes. The primary voltage must be carefully maintained by the

generator so as not to over excite the primary winding. Over excitation will allow the

excitation current to increase exponentially and core saturation can occur leading to damage

to the transformer.

Modern surge arresters should be used to protect the transformer from close in faults. Metal

oxide surge arresters provide better protection than the older thyrite type. A best practice is to

have the arresters mounted as close to the bushing terminals as practical. Most modern

designs now mount the arrester assembly to the transformer tank.

Plants should, as a good practice, carefully monitor the transformers operational data and

insure that strict controls are in place to prevent operation of the MPT beyond its intended

design.

Provisions for spare transformers greatly enhance unit availability by providing “insurance”

when a failure occurs. Major repairs or replacement of an MPT can be a costly and lengthy

process and on-site spare transformers can significantly improve the availability factor for the

unit when a major event occurs.


Rev. 1.0, 12/08/2011 251

Utilization of fixed fire protection and oil containment systems can also reduce collateral

damage and minimize environmental issues during a major failure event and should be

considered as a good practice.

3.3 Maintenance

Preventative and corrective maintenance are essential components of any MPT. The demand

for timely maintenance becomes more critical as the transformer ages. Routine maintenance

of the various transformer components is vital to the life of any power transformer regardless

of its age. An example of a typical maintenance issue would involve the inspection of the

main tank. It should be inspected for oil leaks, rust, and effectiveness of the paint system. All

gasketed flanges, mounting plates, bushing turrets, manhole covers, fittings, and valves

should be inspected and oil leaks documented. Some oil leaks discovered may have severe

consequences if not corrected. For instance, oil leakage on the intake side of a motor driven

oil pump or flange can draw atmospheric air bubbles into the transformer. Bubble formation

can be extremely detrimental to the electrical integrity of the transformer. Oil leaks should be

corrected to address potential reliability and environmental concerns. Any unusual or

excessive noise or vibration should be thoroughly investigated to determine source. Figure 4

illustrates remedial measures to mitigate an oil pump leak. Such measures are not

recommended as a long-term repair.

Figure 4: Excessive Oil Leak on Motor Driven Oil Pump

Cooling system effectiveness requires all components to be fully functional. This includes

cleanliness of air space between radiators and coolers as well as surface area. Shut off valves

should be verified to be in the proper position and secured in place. All fans should be in

place and be fully operational. Repair or replace fans and fan blades as required. Motor

driven oil pumps should be checked for vibration, excessive noise, and balanced phase

currents. As the motor of the oil pumps is immersed in oil, excessive overheating of the

motor can generate combustible gas which will enter the transformer. Defective bearings can

allow the pump impeller to come in contact with the casing ring and discharge small particles


Rev. 1.0, 12/08/2011 252

of metal inside the transformer. The cooling system must be maintained in good working

order to preserve the thermal limitations of the MPT.

The bushings are a vital part of the MPT and have a direct impact on reliability and

availability. They are internally connected to the windings by various schemes such as bolted

connections, draw leads, and draw rods. Many high voltage bushings consist of an oil

impregnated, multi-layer condenser wound on a central tube or rod. The condenser acts as a

voltage divider and grades the line voltage to ground. Lower voltage bushings may be a

condenser type or simply a fixed conductor through an insulator. Many older low voltage

bushings used a compound or plastic filler within the insulator which may contain excessive

levels of Poly Chlorinated Biphenols (PCBs) presenting environmental issues if a failure

occurs. Routine tests, such as power factor, capacitance, hot collar, and thermographic

inspections should be performed and all data referred back to the original nameplate data to

identify potential risks. Trend results and replace bushings when out of tolerance limits are

indicated. Inspections of bushings for poor connections, hot spots, proper oil levels, oil leaks,

or insulator contamination/defects should be performed and documented. Bushings older

than 30 years should be carefully monitored as they are at a higher risk for failure based on

thermal aging. Low voltage bushings enclosed in housings are exposed to greater thermal

stress. A single bushing failure can lead to a catastrophic transformer failure. Figure 5

illustrates an example of an oil filled bushing, in this case contaminated with PCBs.

Figure 5: PCB Contaminated Bushings

The oil preservation system keeps external contaminates such as atmospheric air and

moisture from entering the transformer. This protects both the liquid and solid insulation

system. Oxidation of the oil is minimized and ingress of moisture is prevented. Preserving

the oil quality is paramount to maximizing the life of the insulation system. A number of

different type systems are used including sealed inert gas, inert gas constant positive

pressure, free breathing, and sealed conservator. The function and operation of each type

system used should be thoroughly understood in order to perform proper maintenance.


Rev. 1.0, 12/08/2011 253

The two most common types of sealed tanks used on modern transformers in the U.S. are

pressurized inert gas sealed and sealed conservator. The inert gas constant positive pressure

sealed system (often referred to as nitrogen blanketed) maintains positive pressure of dry

inert gas, usually nitrogen, above the oil. A nitrogen bottle and regulator system maintains a

positive pressure of 0.5 to 5.0 PSI above the oil. The nitrogen used should meet ASTM D-

1993 Type III with a -59oC dew point as specified in IEEE C-57.12.00. Regular inspection

should be performed of the high pressure gauge, high/low pressure regulators, valves,

pressure vacuum bleeder, and oil sump. Never allow the tank pressure be zero or negative

pressure. The sealed conservator system uses an expansion tank (conservator) which is

mounted above the main tank and maintains the oil at atmospheric pressure. An air cell or

diaphragm is placed inside the conservator which is vented through a silica gel breather. As

the oil in the main tank expands and contracts within the conservator, the transformer

“breathes” to atmosphere via the breather. The air cell or diaphragm serves as a barrier and

prevents any external air or other contaminates from coming into contact with the oil. The

silica gel breather dries the air entering the conservator and the indicating silica gel should be

inspected regularly and the desiccant replaced when approximately one-half of the material

changes color. The inspection port on top of the conservator should be removed every 5-6

years and the inside of the air cell or diaphragm inspected. If any oil is observed, a leak has

developed, and the cell or diaphragm must be replaced. The quality of the insulating oil is

highly dependent on proper maintenance of this system.

The quality of the insulating oil affects the health and life of the MPT. This highly processed

mineral oil must be maintained or reduction in the dielectric strength and accelerated aging

will be experienced by the insulation system. It is imperative that an aggressive oil testing

program be in place for testing the chemical and electric characteristics of the oil. Standard

tests and criteria are recommended and listed in IEEE C57.106. By performing trend analysis

of the data, planned corrective action can by implemented before significant deterioration

occurs. Many additional tests can be performed such as particle count, dissolved metals,

oxidation inhibitor, and corrosive sulfur to further refine the assessment of the oil and

determine the maintenance techniques required. All oil will degrade over time. However,

early detection of degradation allows for treatment of the oil in the field. Reconditioning of

the oil will remove moisture, gases, and most particulates from the oil. Reclamation of the oil

removes moisture, aging by-products, gases and particulates from the oil. Oil reclamation can

return service aged oil to a pristine condition and may be both technically and economically a

best practice for large MPTs. If additives for inhibited oil and passivators for corrosive

sulphur mitigation are used, they are sacrificially consumed over time and must be

replenished.

The controls, indicators, and protective devices are usually mounted on the main tank. The

control cabinet contains power supply transfer components, breakers, relays, switches,

controls and terminal blocks for the auxiliary equipment for the transformer. The cabinet

should be provided with weather tight seals and a strip heater to prevent condensation.

Routine inspections should be performed to check for corrosion, water leakage, and

component function. Thermographic inspections should be performed to check for poor

connections and overheating of wiring and components. Oil flow and oil level indicators

should be checked for proper operation including alarm contacts. Pressure relief devices


Rev. 1.0, 12/08/2011 254

(PRD) are mounted on the transformer tank and are a last defense to attempt to mitigate a

tank rupture under major fault conditions and should be routinely inspected. When replacing

these devices, verify the correct pressure setting of the PRD required since various pressure

settings are available. Top oil temperature indicators provide remote monitoring and alarms

functions and should be regularly tested and calibrated. Winding (hot spot) temperature

indicators simulate the calculated hottest spot within the windings. These indicators provide

for monitoring, alarm/trip, and cooling system control functions. Older type indicators are

basically a dial type remote thermometer with set points. Modern electronic control monitors

are available that can provide all functions of the dial types plus additional features for

trending the transformer temperatures. Fiber optics is also available for measuring actual

winding conductor temperatures in lieu of simulated values. Rapid pressure or sudden

pressure relays are normally used on MPTs to provide for rapid tripping of the transformer in

the event of an internal fault. Many utilities have installed redundant relays with two out of

three logic controls to eliminate single point tripping which greatly improves reliability and

availability. All controls, indicators, and protective devices should be regularly inspected,

tested, and calibrated as recommended by manufacturer’s specifications.

An aggressive routine electrical test program should be implemented allowing maintenance

decisions to be data driven. As a minimum, the test program should include the following

tests: winding power factor, bushing power factor and capacitance, bushing hot collar,

winding resistance, excitation, core ground insulation resistance (if external), and insulation

resistance. Thermographic inspections should be included within the test program. All data

analysis should be referred back to base line commission and/or factory and nameplate data.

Additional advanced testing may be performed such as sweep frequency response analysis,

acoustical and partial discharge tests when indicated.

The spare transformer(s) should be maintained in fully operational condition and should

always be immediately available. Components should not be removed and used as spare parts

for other MPTs. When the spare is needed, it is usually installed under tight time constraints.

Routine testing and inspections should be performed in the same manner as an operating

transformer. Adequate critical spare parts such as bushings should be immediately available.



The fundamental efficiency of a main power transformer and associated losses is described

below.

Where: · TL is the total loss for the transformer (Watts)

· NL is the no-load loss at rated voltage (Watts)

· LL is the load loss at rated current (Watts)

· AL is the sum of the auxiliary losses (Watts)

· OP is the output of the transformer (Watts)

· VA is the rated capacity of the transformer (Volt-ampere)

· PF is the power factor of the secondary load


Rev. 1.0, 12/08/2011 255

Total transformer losses are: TL = NL + LL + AL

Transformer output is then expressed as: OP = VA * %PF

Transformer efficiency is given by: %Efficiency = (OP / (OP + TL)) * 100

The condition of the MPT can be assessed by the Condition Indicator (CI) as defined

according to HAP Condition Assessment Manual, ORNL, October 2011.

Industry reliability and availability statistics can be monitored and compared to unit

performance by use of the North American Electric Reliability Corporation’s (NERC)

performance indicators, such equivalent availability factor (EAF) and equivalent forced

outage factor (EFOR). These are universally used by the power industry. Many utilities

supply data to the Generating Availability Data System (GADS) maintained by NERC. This

database of operating information is used for improving the performance of electric

generating equipment. It can be used to support equipment reliability and availability

analyses and decision-making by GADS data users.

Data Analysis of test data can be performed with the assistance and guidelines provided by

various standards and guidelines related to specific analysis required. IEEE C57.104 and

C57.106 standards provide information for testing and analysis of insulating oil. Various

ASTM standards provide testing procedures and methodology. Several companies offer

valuable electrical testing, oil analysis and investigation resources and provides assistance on

interpretation and analysis techniques. Many vendor and reference materials are also

available on all aspects of power transformers.

Determine the MPTs existing capabilities (CPL) and compare results to previous or original

test data (IPL). Assess the efficiency, reliability, capacity needs, transformer energy losses,

and revenue loss. Compare results to new MPT design data (from transformer manufacturer),

and determine potential efficiency, capacity, annual energy loss savings, and revenue gain

(PPL). For the latter, calculate the installation/rehabilitation cost and internal rate of return to

determine major upgrade or replacement justification.

The condition assessment of the MPT is quantified through the CI as derived according to

HAP Condition Assessment Manual, ORNL, October 2011. The overall CI is a composite of

the CI derived from each component of the transformer. This methodology can be applied

periodically to monitor existing transformer and can be monitored and analyzed over time to

determine condition trends that can impact performance and reliability.


reliability indexes or performance indicators as derived according to NERC’s Appendix F,

Performance Indexes and Equations.

4.2 Integrate Improvements

The periodic field test results should be used to update the unit performance characteristics

(CPL). These can be integrated into computer programs to provide on-line analysis results


Rev. 1.0, 12/08/2011 256

and anomalies to all involved personnel. Parameters can be established to trigger various

maintenance or immediate action activities as required. Data trends allow predictive

maintenance to be performed in lieu of reactive maintenance.

As the condition of the MPT changes over time, the CI and reliability indexes are trended

and analyzed. Using this data, projects can be ranked and justified in the maintenance and

capital programs to return the transformer to an acceptable condition and performance level

or indicate the need for replacement for long term reliability and unit performance.


Baseline Knowledge:


USBR, FIST Volume 3-30, Transformer Maintenance, October 2000

Transformers for the Electric Power Industry, McGraw-Hill Book Company, 1959

Transformer Maintenance Guide, Transformer Maintenance Institute, 2001


Hydro Life Extension Modernization Guide, Volume 4-5 Auxiliary Mechanical and Electrical

Systems, EPRI, Palo Alto, CA: 2001. TR-112350V4.

State of the Art

ABB, Service Handbook for Power Transformers, TRES – Transformer Remanufacturing

and Engineering Services, North America, January 2006

CIGRE WG12, 18, Report on Transformer Life Assessment, 2003


Doble Client Committee on Circuit-Breakers and Bushings, Bushing Field Test Guide,

Document BG661

Standards:

IEEE C57.104 – 2008, Guide for Interpretation of Gases in Oil-Immersed Transformers

IEEE C57.106 – 2006, Guide for Acceptance and Maintenance of Insulating Oil in

Equipment

IEEE C57.12.10, Standard Requirements for Liquid-Immersed Power Transformers

IEEE C57.91, Guide for Loading Mineral-Oil Immersed Transformers


Excitation System

Revision 1.0, 11/18/2011

HAP – Best Practice Catalog – Excitation System

Rev. 1.0, 12/21/2011 258

1.0 Scope and Purpose ....................................................................................................... 259

1.1Hydropower Taxonomy Position .................................................................................... 259

1.1.1Exciter Components .............................................................................................. 259

1.2 Summary of Best Practices ............................................................................................. 261

1.2.1Performance/Efficiency & Capability - Oriented Best Practices ...................... 261

1.2.2Reliability/Operations & Maintenance - Oriented Best Practices .................... 262

1.3 Best Practice Cross-references ........................................................................................ 263

2.0 Technology Design Summary ...................................................................................... 263

2.1 Material and Design Technology Evolution ................................................................... 263

2.2 State of the Art Technology ............................................................................................ 264

3.0 Operational & Maintenance Best Practices ................................................................. 265

3.1 Condition Assessment..................................................................................................... 265

3.2 Operations ....................................................................................................................... 266

3.3 Maintenance .................................................................................................................... 267

4.0 Metrics, Monitoring and Analysis ............................................................................... 269

4.1 Measures of Performance, Condition, and Reliability .................................................... 269

4.2 Data Analysis .................................................................................................................. 269

4.3 Integrated Improvements ................................................................................................ 270

5.0 Information Sources ..................................................................................................... 270


Rev. 1.0, 12/21/2011 259


This best practice for the excitation system addresses its technology, condition assessment,

operations and maintenance best practices with the objective to maximize performance and

reliability. The primary purpose of the excitation system is to provide a regulated DC current to

the generator rotor to induce and maintain a voltage in the stator at a set value under normal

operating conditions while varying the generation or absorption of reactive power and supporting

generator terminal voltage under fault conditions. The excitation system must respond to voltage

and frequency excursions and this response must be coordinated with generator capabilities and

protective relay functions to ensure continuous unit reliable generation. Due to its critical nature

the reliability of the excitation system has come under the auspices of the North American

Electric Reliability Corporation (NERC).


Hydro Power Facility → Powerhouse → Power Train Equipment → Exciter

1.1.1Exciter Components

Exciters and excitation systems have evolved from DC generators driven by the shaft of

the generator or by an AC motor to the present solid state systems utilizing diodes or

rectifiers. Many of the original systems are still in service today as a testament to their

simplicity and reliability. The solid state systems may be brushless systems where the

rectification takes place on the rotating shaft and field current is supplied to the rotor

without going through brushes and collector rings. A very basic system is seen in figure

1. Performance and reliability related components of the excitation system include the

low voltage controls, the source of the field current (dependent on the type of excitation

system, i.e. rotating or static), the power source (for a static system), current interruption

or isolation devices (AC or DC field breakers), and the brushes and collector rings /

commutator. For purposes of this BP the excitation system is considered to “end” at the

collector rings or at the point of connection to the rotating field circuit.


Rev. 1.0, 12/21/2011 260

Figure 1: Excitation System Diagram

Low Voltage Controls: The low voltage controls portion, or regulators, of the excitation

system provides the control and protective functions to regulate the DC field voltage and

current supplied to the generator rotor. Field voltage to the generator is controlled by

feedback from the generator instrument transformers. The information provided by these

transformers is used by the ―automatic voltage regulator‖ or AVR to control either the

field of a DC exciter or alternator or the input to silicon controlled rectifiers (SCR‘s)

which in turn determines the magnitude of the main DC field current. These instrument

transformers are normally not provided with the excitation equipment however the

voltage transformer is critical to operation of the AVR. Generally a ―manual‖ regulator is

also provided which functions as a field current regulator to maintain field current at a

fixed value. In some critical facilities redundant regulators may be provided. On some

older units a manual control rheostat is used that allows the AVR to be removed from

service while the unit remains on-line under manual control.

Field Current Source: The predominate field current sources will be either a rotating

exciter feeding the main field of the generator or a static exciter using thyristor bridge

rectifiers (SCR‘s). Another common excitation system is a brushless exciter with a

rotating ac generator and rotating rectifiers

Power Source: For static exciters an AC power source must be provided for the bridge

rectifier. This power source is generally a shunt supply transformer from the generator

terminals but may also be any adequately sized AC supply from the line side of the

generator breaker. For an exciter transformer, sometimes called a power potential

transformer (PPT) or exciter power transformer (EPT), or any alternate supply the rating

must be sufficient to supply the field under all operating conditions, including faults on


Rev. 1.0, 12/21/2011 261

the generator terminals or the transmission system when connected, plus any losses in the

conductors, convertor and transformer itself.

For rotating exciters the power source is usually a permanent magnet generator (PMG)

An alternative source of excitation power is a low voltage plant bus. This is not preferred

due to the possibility of harmonic content from the exciter bridge having a deleterious

effect on other equipment powered from the bus. This power source is not considered in

this BP.

Current Interruption Devices : As the field current cannot change instantaneously for a

close-in or internal generator fault fast suppression of the generator field is necessary to

limit damage. As long as the unit is spinning and there is current in the rotor, energy will

be fed to the fault. Depending on the type and vintage of the system a number of methods

are utilized to dissipate and remove this energy. A field discharge resistor in parallel with

the field winding provides a decay path for the field current when the resistor is placed in

the circuit as the result of a unit electrical trip.

For a fully static system, the field voltage may be forced negative to result in rapid de-

excitation.

For almost all systems field energy is dissipated in a field discharge resistor once the field

breaker contacts open or a protective thyristor(s) is gated.

Collector Rings, Commutators, and Brushes : The brushes function to transfer field

current from a stationary component, the brushes and rigging, to a rotating component.

For a rotating exciter, the output of the exciter armature is delivered by the exciter

commutator and brushes to the main generator field collector (or ―slip‖) rings and

brushes

Non-performance but reliability related components of the excitation system include the

instrument transformers used to measure generator voltage and current.

Instrument Transformers, Voltage and Current : As the generator terminal voltage and

currents cannot be directly measured a means for reducing these values to useful levels

for the regulator is required. These transformers are normally not part of the excitation

system regulator ―package‖. Voltage transformers (VT‘s) reduce the generator stator

voltage and current transformers (CT‘s) reduce the generator stator currents to useful

quantities based on their transformation ratios. These transformers are normally housed in

the generator switchgear and the secondary voltages and currents off any VT or CT may

be used by multiple instruments, meters or relays. Inputs from the VT and CT are critical

to both the controlling and protective functions of the regulator.



Periodic performance testing to establish accurate current unit performance

characteristics and limits.


Rev. 1.0, 12/21/2011 262


local and remote control and decision support systems and other personnel and

offices that influence unit operation and performance.

Real-time monitoring and periodic analysis of unit performance at the Current


performance for the Installed Performance Level (IPL) due to degradation or

component failure.




made (e.g., re-insulation of field, exciter replacement).

Trend loss of performance due to degradation of excitation system components.

Such degradation may be indicated by increased excitation current required for a

given load point or increased operating temperatures.

Include industry acknowledged ―up to date‖ choices for excitation system

components and maintenance practices.


For any given load point the power into the exciter should be periodically

measured and trended for degradation. For a static exciter the power into the

exciter is from the PPT (or EPT). In a rotating system exciter field current and

PMG output serve as indicators of power into the system. Shorts (shorted turns)

or open or high resistance circuits in the components providing power to the

exciter will result in increased losses and degraded performance.

The power out of the exciter, i.e. the delivered field current, is determined by the

AVR (or manual regulator). The amount of field current required for any

operating point should be compared to the original manufacturer‘s curves.

The brush rigging and collector commutator assemblies are most critical

reliability components for both static and rotating exciters. The high temperature

environment, brush dust generated and wear of components due to relative

rotating motion dictates increased focus on these areas. Brushes assemblies,

collector rings and commutators should be inspected frequently. Establish a

temperature profile for collector ring/commutator air temperatures. Trend for

degradation and indication of brush/collector/commutator deficiencies. Periodic

infrared inspection of brushes under load can provide an indication of brush

selectivity issues. On higher speed units brush vibration (and attendant wear,

chipping) may be caused by excessive collector ring runout.

Monitor field insulation resistance to ground.


Rev. 1.0, 12/21/2011 263

Establish normal operating temperatures for other system components and trend

for degradation (e.g., PPT‘s, rectifier bridge).

Electronic and electromechanical (low voltage control) components should be

maintained in a clean and preferably temperature controlled environment.

Manual and motor operated rheostats should be periodically ―wiped‖ (run through

their limits), checked for smooth operation and visually inspected for arcing or

overheating. Drive mechanisms should be inspected and lubricated as required.

AC and DC breakers should be checked per vendor‘s recommendations.


I&C Automation Best Practice

Electrical – Generator



Early exciters were usually a DC generator driven off of the main generator shaft, by an AC

motor or even an auxiliary water wheel. With the development of solid state devices,

rectifier sourced exciters were developed evolving into the fully inverting silicon controlled

rectifier (SCR) bridge(s) used in today‘s solid state exciters. Voltage regulators have

changed from manual control of a rheostat in the field circuit of a DC generator to the present

solid state digital regulators. The regulator will control either the field of a DC exciter or

alternator or it may control the gating of the SCR‘s in a solid state exciter.

Performance levels for excitation systems can be stated at three levels as follows:

The installed performance level (IPL) is described by the unit performance characteristics at

the time of commissioning. For excitation systems these performance levels are defined by

the manufacturers provided guaranteed loss data and by the unit saturation (figure 2) and ―V‖

curves (figure 3) which define the expected field current requirements for a given load

condition. An explanation for the interpretation of these curves is found in IEEE 492.


Rev. 1.0, 12/21/2011 264

Figure 2: Typical Saturation Curve Figure 3: Typical “V” Curves

The Current Performance Level (CPL) is described by an accurate set of excitation system

performance parameters. While current performance can be compared to the IPL curves and

loss data, additional data points (not provided for by the IPL) for temperature measurement

of system components should at some point be collected for baseline and trended over time.

Determination of the Potential Performance Level (PPL) for excitation system will entail

system improvements that provide minimal reduction of losses and non ―performance‖

related improvements such as improved response times offered by solid state systems. For a

given generator rating improvements in excitation performance can only be expected to

restore the original IPL relative to field current required at a particular load point.


Excitation system efficiencies, as a measure of losses, are the sum of the electrical and

mechanical losses in the equipment supplying excitation. This will include losses in exciter

field circuits, manual and motor operated rheostats, voltage regulators, PPT‘s, collector and

commutator assemblies, motors used in the system, switchgear and any electrical connections

in the power circuit. These losses are directly correlated and vary based on the amount of

field current which is directly correlated to the operating power factor and load.

For a state of the art excitation system with a fully static exciter and digital voltage regulator

the total excitation losses may approach 4% of the total generator losses at rated load

condition. For a 33 MVA unit this total may be 15 to 30 kW. In older systems which

include manual and /or motor operated rheostats, main exciter field windings, a pilot exciter


Rev. 1.0, 12/21/2011 265

and commutators not found in a state of the art system these losses may approach 10%. Here

the value may be 40 to 60 kW. In both cases these IPL values are generally provided as

calculated data by the manufacturer and very difficult to determine empirically as

independent test for the exciter.

The more significant gains as defined by the PPL are in the area of reliability, improved

exciter response time (transmission system stability, minimized fault damage), reduced

maintenance requirements and improved flexibility and integration with modern control and

protection systems. Reduction of losses is not a prime consideration in the decision to replace

an existing system.



USACE Hydro Plant Risk Assessment Guide (ref. 1) provides a methodology for assessing

the condition of a system based on its age, operation and maintenance history, availability of

spare parts and service support, and test performed on both the power and control circuitry.

Some of the factors considered in this assessment follow.

The NEMA insulation class ( B, F, H, etc.) will determine the operating temperature limits.

The electrical insulation integrity of this insulation and the system is reduced with increasing

age. All electrical insulation deteriorates over time due to increased exposures to the

cumulative effects of thermal stress and cycling, vibration and mechanical damage, and

deleterious contaminates. Age also determines obsolescence status and availability of vendor

technical support and spare parts. A variety of electrical tests may be performed to aid in

assessing insulation condition.

Obviously, these condition assessment factors are closely related. The evaluation should also

consider the failure and forced outage history. It is likely, however, particularly for older

units, that there may be a lack of history, maintenance records, and design documentation to

supplement the assessment.

Infrared thermography can be used to monitor deterioration of bolted electrical power

connections, collector/commutator performance and rheostat performance.

Winding resistance and system insulation resistance should be measured periodically to

detect deterioration. Field insulation resistance may be continuously monitored on line and

trended.

Brushless systems should be inspected stroboscopically for blown fuses if applicable. In

some cases a blown fuse can cause a cascading overload of remaining fuses.

Collector ring/commutator and brush rigging condition should be evaluated. Ring film

condition, commutator condition and overall cleanliness have a significant effect on

reliability. A typical collector ring, brush rigging assembly, commutator assembly is seen in

figure 4.


Rev. 1.0, 12/21/2011 266

Bridge temperature, transformer temperatures, cabinet air temperatures and collector ring

temperatures can provide an early indication of deterioration. Figure 5 shows a typical solid

state system cabinet.

Figure 4: Collector/Commutator/Brushes Figure 5: Typical Solid State Cabinets

3.2 Operations

It is critical that the design and capacity of the exciter match the operational requirements.

Operation of the exciter and generator must be maintained with the manufacturer‘s capability

curve. An example capability curve can be seen in figure 6. For the excitation system critical

operation is in the over excited region of the curve where field current is a maximum and

temperature limits may be reached. Operation outside these limits results in increased

heating and rapid deterioration of insulation and reduction of service life. Temperature limits

for the field are determined by the NEMA insulation class.


Rev. 1.0, 12/21/2011 267

Figure 6: Typical Generator Capability Curve

For generating units whose capacity (output) has been uprated without exciter replacement

consideration should be given to the number of collector ring brushes required by increased

field current, the change in the generator short circuit ratio if applicable, and operating

temperature limits.

Shorted rotor turns may increase excitation requirement for a given generator load, kVA.

Rotor insulation class may limit kVA output due to temperature limits. Deratings of the

excitation system may also impact kVA output of the unit.

3.3 Maintenance

The frequency of maintenance will best be determined by consideration of manufacturer‘s

recommendations, the age of the unit, the operating mode of the unit, environmental

conditions and the failure history of the unit. No one frequency recommendation will be

applicable to all units. The maintenance of excitation system components is also a significant

factor in its performance capabilities. Manufacturer‘s recommendations provide a basis for

items necessary to maintain. These recommendations should be adjusted based on the actual

age, operating conditions and operating environment in order to maximize life expectancy.

Cleanliness is required to minimize potential for electrical tracking and grounds as well as to

prevent degraded cooling or heat transfer.


Rev. 1.0, 12/21/2011 268

The collector ring/commutator and brush rigging assembly are probably the most

maintenance sensitive component of the system when it comes to reliability. The generation

of carbon brush dust due to the relative motion between the rings/commutator and the

brushes provides opportunities for field grounds and flashovers, including fires. Brush

condition (length, freedom of movement, leads discoloration) should be visually checked

frequently depending on how the unit is operated. The collector ring film should be visually

inspected and run-out measured to be within manufacturer‘s tolerance. If necessary the ring

may be required to be trued, in situ or removed. The ring film may need to be removed and

re-established. In either case the ring finish should be within manufacturer‘s tolerance. If

necessary as indicated by insulation resistance measurements the brush rigging should be

cleaned.

Inspect the commutator and ensure that the commutator insulation does not protrude above

the copper bars. If so, undercut per manufacturers recommendations.

Rheostats should be inspected, cleaned to ensure uniform, low contact resistance and

lubricated for free movement. A typical rheostat is seen in Figure 7.

Figure 7: Motor Operated Rheostat

Excitation system AC and DC breakers and contactors should be tested, inspected, and

maintained per the manufacturer‘s recommendation. Particular attention should be given to

DC breaker and contactor contacts for wear and electrical erosion.

Equipment enclosures should be cleaned and any vent filters replaced as necessary. Vents

should not be obstructed. For solid state systems with force cooled bridges verify operation

of bridge fans, lubricate as required.


Rev. 1.0, 12/21/2011 269

Both solid state dry type and oil filled PPT/EPT‘s should periodically meggered and have

turns ratio tested. If fitted with fans they should be cleaned and operation tested. Oil filled

PPT/EPT‘s should be inspected for tank and bushing leaks. Transformer bushings should be

cleaned and oil level checked. If fitted with oil pumps and motors their operation should be

tested. Transformer oil should be checked for dissolved gases and quality.



Excitation system losses (rheostat, brushes, transformers) and excitation system availability

are all measures of condition and reliability. Losses associated with the exciter may include

rheostat losses, brush contact losses, brush friction losses, and windage losses and may

approach 15-30% of the unit full load losses. Generator rotor I2R losses are included with

the generator and not considered in the excitation BP.

Any I2R loss, which is a waste heat loss, may be reduced by reducing R. ―R‖ is the

resistance which is a function of temperature and physical properties of copper in the

excitation system components. R varies but not significantly with the temperature changes in

operation. ―I‖, the current, may vary significantly. The amount of current, the most

significant factor in the loss equation is dictated by the load. Exciter losses are the total of the

losses in the equipment supplying excitation. This equipment is minimized with a static

system, thereby reducing these losses.

Rheostat losses are the I2R losses of the rheostat if used. This is eliminated when using a

static system.

Brush contact losses are the electrical losses in the collector ring brushes. Prudent

maintenance of collector ring, commutator (eliminated with static system) and brush rigging

minimizes these losses.

Brush friction loss is a mechanical loss due to rubbing friction between the brushes and

collector rings and/or commutators. Elimination of the commutator brushes with a static

system reduces these losses.

Friction and windage losses are the power required to drive an unexcited machine at rated

speed with the brushes in contact (excitation system contribution to this loss is typically

minimal and unavoidable).

The key measurements include field current If, field winding resistance R, temperature T, and

brush voltage drop in volts.

4.2 Data Analysis

The CPL, relative to losses, is described by an accurate set of unit performance

characteristics determined by unit efficiency testing, which requires testing per IEEE 115

methods. The CPL relative to field current requirements of the unit is made by comparison

to the saturation and ―V‖ curves. Failure to meet the IPL for field current may be due to

shorted rotor turns.


Rev. 1.0, 12/21/2011 270


Reliability issues, obsolence issues or impending unit uprate may warrant complete

replacement of the existing exciter. The preferred option is a completely solid state unit

which offers the following advantages [4]:

Eliminates high maintenance and obsolete components

Eliminates time constants associated with exciter field components and provides fast

system voltage recovery and transient stability

Provides data recording capability for trending and troubleshooting

Offers an opportunity to increase original field excitation and uprate the unit.

Provides digital communication capability that facilitates remote control and

monitoring.

Provides option of backup regulators

Enhanced control features such as a power systems stabilizer, power factor and VAR

control.

Eliminates losses associated with commutator brushes and rheostats

It may not be necessary to replace the rotating exciter to restore unit reliability. Replacement

of the pilot exciter/voltage regulator with a digital system may be sufficient to improve unit

reliability; however, the response time of the system will not be optimized as with a full

static system. While replacement of the voltage regulator only is a reasonable compromise,

replacement with a full static excitation system is the best solution.

NEMA class F or H insulation (maximum operating temperature 155 or 180 oC,

respectively) should be used for rotor pole windings. For unit uprates brush capacity should

be evaluated for additional field current requirements. Constant pressure brush springs should

be used for collector and commutator brushes.

Location and placement of a new solid state system and PPT (EPT) is often a challenge in

existing plants. Once locations for new equipment have been determined consideration of

the operating environment may indicate the need for additional cooling for reliability of the

low voltage electronics.


Baseline Knowledge:

USACE – Hydro Plant Risk Assessment Guide, Appendix E4 Excitation System Condition

Assessment

EPRI –EL-5036, Volume 16, Handbook to Assess the Insulation Condition of Large Rotating

Machines


Rev. 1.0, 12/21/2011 271

IEEE 115 – Guide for Test Procedures for Synchronous Machines

Hydro Life Extension Modernization Guide, Volume 3: Electromechanical Equipment, EPRI,

Palo Alto, CA: 2001. TR-112350-V3.

State of the Art:

Basler Application Notes – 16 Reasons to Replace Rotating Exciters with Digital Static

Exciters

EPRI 1004556 – Tools to Optimize Maintenance of Generator Excitation Systems, Voltage

Regulators and Field Ground Detection

Standards:

IEEE Std 492 – Guide for Operation and Maintenance of Hydro-Generators

NERC GADS – Top 25 System/Component Cause Codes


Instruments and Controls for Automation

Revision 1.0, 12/05/2011

HAP – Best Practice Catalog – I&C for Automation

Rev. 1.0, 12/05/2011 273



1.1.1 Plant Automation Components ............................................................................. 274


1.2.1 Performance / Efficiency & Capability - Oriented Best Practices ........................ 278

1.2.2 Reliability / Operations & Maintenance - Oriented Best Practices ...................... 279



2.1 Technological Evolution .............................................................................................. 281

2.2 Design Technology ...................................................................................................... 281




3.2 Operations .................................................................................................................... 291

3.3 Maintenance ................................................................................................................. 294




Rev. 1.0, 12/05/2011 274


The primary purpose of an automatic control system or automation system is to allow through

computerized control the automatic starting, stopping, safe operation, and protection of any

equipment being controlled. In the context of this document, that equipment is a hydro

generating unit and its associated components and auxiliaries. An additional benefit to an

automation system is the ability to operate the hydro generating unit in a more efficient manner.

Hydro generating units have been monitored and controlled by human operators for many years,

both locally and remotely.. Unfortunately, the generating efficiency is hard to be adequately

optimized by human operators due to the vast number of variable parameters spanning multiple

systems that can affect unit efficiency and also because the variables can change rapidly.

However, a computer system has the capability to analyze numerous parameters to determine

optimum performance settings for a generating unit many times per second, which brings such a

system a distinct advantage when trying to squeeze every last megawatt out of a limited supply

of water resources.


Hydropower Facility → Powerhouse → Instrument and Controls → I&C for Automation

1.1.1Plant Automation Components

Performance and reliability related components of a hydroelectric plant instrument and

control system will vary based on the automation supplier‘s design. This component

listing is based on a PLC (programmable logic controller) or RTU (remote terminal unit),

PC based data server, PC based HMI (human machine interface), conventional panel

boards for manual control and SCADA (Supervisory Control and Data Acquisition)

software. The term ‗controller‘ will be used to represent either a programmable logic

controller or current technology RTU.

PLC (programmable logic controller): The function of a PLC is the heart of digital

control system with programming capability that performs functions similar to a relay

logic system. A PLC consists of a CPU (central processing unit), memory, power

supply and a means of communications to I/O and other devices. The software

includes ladder, block, sequential, structured text and other logic programming to

control devices.

RTU (remote terminal unit): The function of an RTU is to collect data and is similar

to a PLC. Sometimes, it may be termed as PLC depending on the vendor terminology.

RTU is generally associated with older (prior to 1998) control systems with minimal

control capabilities, though it may also be a perfectly acceptable term for a current

vendor offering. Use caution when making a quick assessment of systems based on

these acronyms of RTU and PLC. The RTU is not always a lesser controller.

Controller: This can refer to either a PLC controller or a current technology RTU.

HMI (human machine interface): The function of the HMI is to be the interface for

the operator to the control system. The HMI is normally a PC as the client portion of

a client/server architecture. In some cases, the HMI and the server are the same PC.


Rev. 1.0, 12/05/2011 275

Data Server: The function of a data server is to link to the controllers and the network

to send data to the HMI and receive operator input from the HMI back to the

controllers. The data server is normally a PC in a client/server application.

Control LAN (2)

Central Hydro Dispatch

Control Center

Secure Isolated

Wide Area Network

Control LAN (2)

Ethernet LAN

Local Operating

Workstation

Redundant Serial

Communication Channels

GPS

Clock

Redundant Plant

Common PLC's Unit PLC's

One Per Unit

Remote

Switchyard I/O

Remote

Switchyard I/O

Remote

Unit I/O

Remote

Unit I/O

Unit

Intelligent

Electronic

Devices

Efficiency

Optimization

Firewall

System Architecture For A Typical Automated Plant

Plant

Intelligent

Electronic

Devices

Figure 1: Typical Control LAN

Network LAN (local area network): There are normally two major networks in a

hydroelectric control system.

The TCP/IP network (Ethernet) links the server(s) to the HMIs, the

controllers, data historians, firewall, and other Ethernet based devices. This is

shown as the Ethernet LAN in Figure 1.

The I/O network may also be Ethernet, though it is commonly a protocol used

by the controls supplier such as Profibus™, Modbus™, DeviceNet™ etc.

This is shown as the Control LAN in Figure 1.

There are also secondary network connections to 3rd

party devices tied directly

to a controller through serial or Ethernet. This is shown as the links to the

plant or unit electronic intelligent devices in Figure 1.

GPS Clock: This is for time synchronization in the control system.


Rev. 1.0, 12/05/2011 276

SCADA (Supervisory Control and Data Acquisition): SCADA unfortunately tends to

be an ambiguous acronym. Suppliers and end users have widely varying

interpretations of what comprises a SCADA system. (See also RTU definition

above.) As shown in Figure 2, an older SCADA system consists of RTUs (remote

terminal units) that tie back to a central processor that primarily collects data and

commonly uses proprietary communication protocols. Some controls suppliers refer

to their current offerings (Dec. 2011) as a SCADA system, which has the same

capabilities as a PLC based system or even is exactly a PLC based system. This can

lead to some confusion. Generally, older SCADA/RTU systems (designed prior to

1998) have limitations in both logic handling and communications, which make them

the candidates for upgrade. Over the decade, SCADA systems, PLC based systems

and DCS (distributed control systems) have migrated towards being synonymous.

These acronyms and their meanings are usually vary with the culture or industry in

which they were initially installed.

I/O (wired input and output to field devices): The function of I/O is to send

commands to devices or receive information from devices.

Traditional Analog and Discrete I/O: These are wired inputs and outputs that

use voltage or current representing the status of a device, values and/or set

points.

Hybrid I/O: Hybrid I/O varies from traditional I/O in that digital

communications are carried on the same wires as the voltage or current. This

digital information generally contains diagnostic information about the

connected device. Devices that support HART™ on top of a voltage signal

are an example of a hybrid.

Smart I/O: This communication signal is entirely digitalized. The accuracy

exceeds traditional analog and it contains diagnostic information about the

connected device.

Safety I/O: This varies from traditional I/O in that the controller periodically

tests the I/O to verify that the controller hardware is functioning properly.


Rev. 1.0, 12/05/2011 277

Figure 2: Common Older Style SCADA System [5]

Local Control (definition): Controls located at the equipment itself or within sight

of the equipment. For a generating station, the controls are located on the unit

switchboard-governor control station.

Automatic Control (definition): An arrangement of controls that provide for

switching or controlling, or both, of equipment in a specific sequence and under

predetermined conditions without operator intervention after initiation [1].

Non-performance but reliability related components of a control system.

Firewall: The function of a firewall is to restrict and protect the plant control

network from outside unauthorized access. The firewall restricts communications

in both directions protecting the process and data.

UPS (uninterruptible power supply): The function of the UPS is to provide

temporary power to a system in case of main power failure. The UPS also acts as

a power filter to protect control equipment. At hydro facilities, a large DC battery

bank can also supply backup power through an inverter to the control system.


Rev. 1.0, 12/05/2011 278

IDS (intrusion detection system): This device resides on the process control

network to detect and log any intrusion attempts – failed or successful. Logs from

firewalls can also be used as a limited form of intrusion detection.

Historical Archive: The function of the historical archive is to store historical

information from the control system.

Reporting: The function of reporting is for GADS (Generating Availability Data

System, as required by NERC - the North American Electric Reliability

Corporation), production, scheduling etc.. This is often accomplished on the

server or client.

Syslogs: This is an important function to meet NERC-CIP requirements as

defined below. Syslogs record software events from the computers, firewalls and

other network devices that support Syslogs.

Engineering Workstation: The function of the engineering workstation is to

configure the software for the control system controllers, servers, HMIs and other

controls equipment.

Efficiency Optimization: This is a program that runs on top of the control system

to maximize efficiency of the plant.


1.2.1Performance / Efficiency & Capability - Oriented Best Practices

Use supervisory control that takes into account weather, demand, headwater and

tailwater levels, fish habitat, outages, and other variables.

Use advanced control algorithms, within the controller, to optimize generator

efficiency.

There should not be more than eight actionable alarms per hour per operator

at any plant or for each operator at a central control facility.

Test all software before downloading or installing.

Design local control to be independent of the digital controller system in that the

units can be operated from a bench board without the controllers and/or SCADA

system in operation. Small generating units would be exempt from this practice.

Compare long term trends, seasonal and annual, to measure performance. Figure

3 shows a complex control system LAN (local area network) with its own

historian. This control system LAN ties back to a corporate LAN which has its

own historian. This structure allows operators to create their own trends locally.


Rev. 1.0, 12/05/2011 279

The corporate historian allows technical personnel the ability to study long term

data. Figure 4 shows a similar complex system in hierarchical form.

Figure 3: Control System at a Hydroelectric Plant, Showing Connections to a Central Location – Courtesy of

CERT [4]

1.2.2 Reliability / Operations & Maintenance - Oriented Best Practices

Use redundant power supplies and/or a UPS (uninterruptible power supply) or use

the DC battery power, normally available at a hydroelectric facility, as an

emergency backup.

Use redundant controllers for critical control and communications.

Design the local control LAN to be redundant or in a ring.

Design the I/O network (for remote I/O drops) to be redundant or in a ring.

Units and all ancillary equipment should automatically go to a safe state on failure

of a PLC or failure of critical instrumentation.


Rev. 1.0, 12/05/2011 280

Security is now part of reliability and is to be a part of the design, maintenance

and upgrade of all parts of the control system.

Use a firewall along with IPSEC (encryption) to protect the local control LAN.

Periodically review the firewall Syslogs for intrusion attempts or unauthorized

access. It is recommended to add an intrusion detection for large systems and at

the central control.

Analyze every port, service and application of all PCs on the control LAN.

Remove or disable all unneeded ports, services and applications on those PCs.

Review these PCs periodically.

Train local maintenance to periodically monitor the health of the control system.

Design the system so that online diagnostics are available and clear to operations.

Monitor corrosion and temperature in cabinets.

Figure 4: Central Control to Multiple Hydroelectric Plants [12]


I&C – Operator Base System

I&C – Condition Monitoring

Mechanical - Generator

Mechanical – Governor

Off-Site

LAN

Excitation Turbine Governor Stat ic Start. Converter

Turbine Contr . BoardMotor Contr . Center

WAN

Process

Manual Control Directly at Process Elements

Gate Control Board Switchgear ,Transfor .

Central Control

Room with Centra l

Computer

Local Control

Boards

LAN

LAN

Unit 1to n

Power plant 1 to n

Local Subcontrol

Panels

Control Boxes

Centralized

Local

Local

Individual

Regional Control

Center


Rev. 1.0, 12/05/2011 281


2.1 Technological Evolution

Automatic control systems for hydroelectric units based on electromechanical relay logic

have been in general use for many years and, in fact, were considered standard practice for

the industry. Within the past few decades, microprocessor-based controllers have been

developed that are suitable for operation in a power plant environment. These computer-

based systems have been applied for data logging, alarm monitoring, and unit and plant

control. Advantages of computer-based control include use of graphical user interfaces, the

incorporation of sequence of events, trending, automatic archiving and reporting into the

control system. The incorporation of artificial intelligence and expert system capabilities

also enhance the system [2].

The initial upgrade for older hydroelectric plants has been from a system that relied primarily

on electromechanical relay logic to a computer based Supervisory Control and Data

Acquisition (SCADA) systems. In an era of deregulation and competition, management

needs more information than ever before, and as quickly as possible, regarding its own costs,

efficiency and the market price for energy. That need for information is leading to the

upgrading and re-engineering of SCADA systems nationwide with new software and

hardware that is more productive, reliable, and which utilizes open standards architecture

[11].The early SCADA systems used proprietary network communications and had

rudimentary logic and information. Today‘s systems include more powerful controllers

(PLCs or RTUs), open architecture (TCP/IP, DN3, Modbus™ etc.) and personal computers

for HMIs (human machine interface).

2.2 Design Technology

Automation system design, operation, and maintenance have a major impact on unit

efficiency, plant overall generation, and reliability. Best practice for the automation system

begins with the ability to safely and securely control the entire facility both locally and

remotely. The security of a control system supplants many previous design parameters, such

as ease of remote network access, open wireless communications and easy physical access.

Once a secure and fail-safe system is in place, the control system is then ready for

optimization and high level control. Figure 5 shows a control system with firewalls and

intrusion detection.


Rev. 1.0, 12/05/2011 282

Figure 5: Securing a Typical Hydro Facility – Juniper Networks example [7]

Cyber Security (some overlap with hardware and software design)

Government owned hydroelectric facilities cyber security policies will fall under federal

compliance requirements with both NERC [13] (North American Electric Reliability

Corporation) and FISMA [3] (Federal Information Security Management Act). The general

rule is that larger government owned facilities and facilities considered ‗critical‘ fall under

the stricter NERC standards which include substantial penalties, if violations are egregious.

The guidelines (NERC or FISMA) are determined by the management of each utility and

their interpretation of the selection guidelines along with agreement from federal officials.

Brief summaries of the two standards are listed in this document since they are crucial to the

design or the upgrade of a government owned hydroelectric control system. NERC standards

apply to private or public owned utilities that fall under the NERC domain. The standards

are in the NERC-CIP 002-009 and in FISMA‘s NIST 800-53 documentation. In particular,

pay attention to appendix J of NIST 800-53 and NIST 800-82 [14].

At the 2011 ―East Tennessee Cyber Security Summit‖, several vendors remarked that 80% of

security incidents are discovered by 3rd parties. These 3rd parties may be local law

enforcement, FBI, banks or the media. The overwhelming number of corporate entities that

were compromised did not have the ability to detect an intrusion nor a system in place to


Rev. 1.0, 12/05/2011 283

track the intrusion. Intrusions may go on for weeks or months without being detected or

reported. The importance of cyber security cannot be over stated.

NERC Guidelines

NERC Critical Infrastructure Protection (CIP) standards relies heavily on documentation.

Compliance with NERC-CIP should not be interpreted as being secure. [13]


A secure reliable automation system that supports high level supervisory optimization is no

longer a difficult technical achievement. The proper design of the automation system will

allow for fail-safe local control, redundancy, secure communications and automated

scheduling with optimization. Optimization routines are readily available from 3rd

party

vendors or may be written in-house with software packages that are becoming easier to

program and employ standard communication protocols.

As the state of the art technology, critical control systems that may cause physical harm,

equipment damage or significant economic loss upon failure should have an appropriate level

of redundancy. But, not all redundancy listed below is required or recommended for all

systems due to the expense involved.

Redundant Power Source

This is the most common form of redundancy and is recommended for all control

systems. A redundant power source may be a UPS with the understanding that the

UPS has a time limit in minutes based on the load and battery size. A UPS may also

be used as a clean power source. Controllers commonly have the ability to be wired

to dual power sources as a fundamental feature.

Redundant Controller

If a redundant controller is not used, verify that a failure of the controller will not

inflict equipment damage or harm personnel. The system must have a safe mode on a

loss of the lone controller. The mean time between failures (MTBF) of a system with

redundant controllers, redundant power supplies and redundant communications is

nearly 10 times that of a standalone control system, see the result data in Table 1

from the study performed at the Large Hadron Collider Project in Europe using the

Siemens 400 series PLCs [10].


Rev. 1.0, 12/05/2011 284

Table 1: Redundant Controller MTBF

Standard System Redundant System

1 CPU S7-414 2 CPU S7-414 4H (in separate racks)

1 Power Supply 2 Power Supplies (one in each rack)

1 Communications path to I/O 2 Communications paths to I/O

MTBF = 6.0 years MTBF = 60.0 years

Redundant Servers and Clients

In client/server architectures, it is critical to have redundant servers. A server can be

removed from service for patches and security modifications without shutting down

the system. Personal computers (servers) have a high failure rate compared to

controllers and should always be redundant. HMIs (clients) should be redundant so

that an operator will not be blind on the loss of a lone operator‘s station. If the plant

is normally operated remotely, a redundant operator station may not be required and

its replacement may be made on the next business day without disrupting operations.

Redundant Networking

The cost of networking equipment has dropped dramatically. It is recommended to

have redundant networking on critical systems or use a network ring so that a single

break in the network will not shut down communications. Dependency on a single

network switch is problematic and should be avoided.

Redundant I/O

This is rare for most hydro applications. It is more common to have critical data

points, such as headwater level, to have dual sources. Vibration, temperature and

other critical data also have multiple sources and are not dependent on a single input.

Ideally these critical control inputs should be distributed among different I/O cards.

Safety I/O

This I/O is continuously monitored by the controller through self-checks. The

controller can detect a failed I/O point and respond appropriately to this failure. It is

not a requirement to use safety I/O in the majority of hydro control systems. If it is

available and the cost is not prohibitive, it is recommended.

Hot Swap

An I/O or communications card should be replaceable without the need to power

down the backplane (I/O rack) or without losing communications to the remainder of

the cards mounted on the backplane.


Rev. 1.0, 12/05/2011 285

It is essential that the following functions can be carried out under backup

conditions or failure of the main control system (PLC or RTU) [12]:

Emergency stop

Operation of spillways

Operation of high voltage circuit breakers and isolating switches

Starting and stopping of generator/turbine units

Operation of the intake gate/turbine isolation (shutoff) valve

Governor and excitation adjustments



It is noticed that some key items are missing in control systems in even recent installations

or upgrades of hydropower facilities in the United States (Dec. 2011). The items listed in

this section will enhance IEEE Std 1249:1996 [1], which is now undergoing a revision.

Engineering and operations should carefully consider all these items in the control system

selection. The overall goal of automation system is dependability, as the majority of hydro

facilities are not manned 24/7. This listing is to promote the best selection for a hydro

control system based on the needs for maximum system availability, safety of equipment and

personnel, system optimization, standardized communications protocols, ease of maintenance

and security.

The first step in assessing an automation system would be the determination of the condition

of existing equipment which must be controlled. A major portion of that assessment would

be the condition and capabilities of any required sensors or feedbacks already present. The

following information will be a guide through the various systems necessary and help

determine any upgrades which might be required.

Turbines

While the actual best practices to be considered for hydro turbines is being covered in

another guide, there is still important information which must be gathered in order to allow

the automation system to operate a unit at optimum efficiency. Depending on the design of

the turbine, different levels of testing will have to be performed to determine the overall

operating characteristics of the turbine. For instance a set of efficiency curves will have to be

developed for a Francis unit over a range of flow, headwater elevation, and tailwater

elevation conditions. But for a Kaplan unit much more data must be collected to cover all the

blade tilt positions as well as the range of water flow conditions. Each type of turbine will

have its own specific variations but basically a complete set of turbine efficiencies must be

available for input into the automation software. Additionally the flow instrumentation,

headwater elevation instrumentation and tailwater elevation instrumentation must be accurate

and must have data outputs which are compatible with the requirements for the automation


Rev. 1.0, 12/05/2011 286

computer. Of course converters can be used if necessary. Typical efficiency curves for a

Kaplan and a Francis turbine are shown below in Figures 6 and 7, respectively.

Figure 6: Kaplan Turbine Figure 7: Francis Turbine

As can be seen from these curves the maximum efficiency point for a Francis turbine is

extremely narrow while the Kaplan turbine has higher efficiencies over a much wider range.

The Kaplan turbine achieves these wider ranges due to the added capability to alter the blade

angle as operating parameters change. The control system needs to be assessed to verify that

it can automatically control a unit in its highest efficiency range.

Governor Systems

The condition of the governor system and its instrumentation is key to optimizing hydro unit

efficiency. It really does not matter if the governor is digital, electronic, or mechanical as

long as it is in good operating condition and has tight feedback loops. Obviously a digital

governor has an advantage in the fact that it will be the easiest to interface with the

automation system but as long as the governor has good tight response to control changes

and accurate instrumentation to provide feedback to the automation system you can achieve

optimal efficiency.

Generator

While generator efficiency is mostly dictated by its initial design, the automation system

must take into account the overall capabilities of the unit. Each generator has a specific

capability curve which operating conditions must be monitored against to ensure no damage

occurs to the unit. Of course these capabilities can be affected (lowered) by other

components such as the excitation system, power cables, breakers capabilities, transformers,

etc. The overall capability limits of the unit is vital information which must be considered by

the automation software. In general the instrumentation required to monitor these limits will

also be used by any efficiency calculations made by the system. A typical generator

capability curve is shown below in Figure 8.


Rev. 1.0, 12/05/2011 287

Figure 8: Typical Generator Capacity Curve

Excitation Systems

Again it really does not matter if the exciter is of digital or mechanical design as long as the

equipment is in good working order and has adequate response times. However, a digital

exciter again has an advantage in the fact that it will be much easier to interface with the

automation system. Optimally the excitation system will have the capacity to operate the

generator anywhere on the capability curve required. However, in some instances the

existing exciter will not have the capacity required and those limits must also be considered

in the automation system software.

Table 2 lists minimum instrumented inputs and outputs on an automated control system, such

as a PLC, to control various devices or systems. The goal of having these levels of control is

to allow fully automated control of a plant from a remote site with scheduling and minimize

the need for operators at the plant full time. The existing system needs to be assessed to

verify it can meet these minimal criteria.


Rev. 1.0, 12/05/2011 288

Table 2: Typical parameters necessary to implement automated control

Control Action Inputs Outputs

Unit Start/Stop

Gate limit

Gate position

Breaker status

Governor hydraulics

Unit speed

Unit protective relays

Generator voltage

Brake release

Gate operator

Cooling water valve

Exciter

Start circuit

Unit selection

Breaker trip/close

Unit synchronizing

Unit speed

Gate position

Gate limit

Breaker status

Generator voltage

Bus voltage

Breaker select

Breaker closing

Unit select

Speed adjust

Voltage adjust

AGC

Unit status

MW

MVar

Unit protective relays

Set point

Unit selection

Power adjust

Synchronous condensing Draft tube depression

MW

MVar

Power adjust

Excitation

Draft tube depression

Unit selection

Turbine optimization

Head

Blade angle

Gate position

MW

Gate operator

Power adjust

Unit selection

Trash rack control Differential pressure

Trash raking system

Power adjust

Gate operator

Black start

Protective relays

Bus voltages

Generator status

Breaker status

Generator voltage

Unit power

Generator start

Unit synchronizing

Breaker close (dead bus)

Power adjust

Voltage regulator

Unit selection

Breaker selection

Base load control

Unit status

MW

MVar

Gate position

Gate limit

Set point

Power adjust

Gate operator

Unit selection


Rev. 1.0, 12/05/2011 289

Control Action Inputs Outputs

Voltage control (AVC)

Unit status

Breaker status

MW

MVar

Bus voltage

Set point

Generator voltage

Voltage regulator

Unit selection

Remedial action schemes

RAS initiation

Generator selection

Breaker status

Unit status

System frequency

Breaker trip

Breaker selection

Forebay selective withdrawal Water temperatures

Gate position

Gate operator

Unit select

Alarming

Audits, performed by the authors of this section, of hydroelectric control systems have found

many installations with minimal alarming, or the alarming was initially configured but never

optimized. Operators routinely ignored alarms and, as a result, missed critical information.

Frequently, numerous alarms are presented to an operator when a single event occurs. Many

of these alarms are excessive and may lead the operator to an incorrect action. These

secondary alarms should be grouped into a single alarm, to a primary cause or inhibited

based on the primary alarm. The existing alarming system needs to be assessed to see how it

compares to the criteria in Table 3.

Controls studies have determined that the optimum number of actionable alarms that an

operator can properly handle is 6-8 per hour [6 and 8]. Where alarms exceed this threshold,

the alarming configuration or the operations of the system itself should be studied and

corrected during engineering and operations. Alarms that require no action on the part of the

operators should be investigated for removal from the system or placed automatically into a

historical archive for reference only to free the operator. Table 3 lists reasonable goals for

alarm systems.

Discrete devices, such as pressure switches, temperature switches, proximity switches, device

statuses etc. should all be installed in a fail-safe manner. A failed device or an alarm state

of the device will trigger an alarm. This is a fail-safe design. Where there are multiple

discrete devices monitoring a single system, such as turbine vibration, the switches are

recommended to be wired to different I/O cards. Just be mindful of not putting all critical

measurements on one I/O card. If the I/O card fails, important information protecting the

process can be compromised. Check the quality and type of discrete I/O of the existing


Rev. 1.0, 12/05/2011 290

system. In some older facilities, the quality of the wiring may need to be assessed. Older

wiring may have cracked or even missing insulation.

Historical Data

Historical data is vital to troubleshooting and optimizing a control system. There are

basically two types of historical trending. The first type is the near real-time trending,

continuously displayed trend used by operators going back a few hours or minutes of a

process and up to near real-time. The second type of trending is for long-term archiving.

Audits of control systems have discovered the historical trending that was never archived or

improperly configured, and/or the historical files were too short of duration to be of

usefulness in troubleshooting or for optimizing. Assess the current ability to create long term

trends and be able to export to a database for analysis.

All alarms should be trended and archived. Historical archiving of discrete points is recorded

on an exception basis. Analog points should be archived based on common sense in terms of

the deadband and frequency of data collecting. A slow-moving temperature measurement

may only need to be collected every 5 seconds. A fast analog, such as flow or pressure, may

be collected every second or even faster if the I/O is capable of scanning at high speeds (>

250 ms). The deadband of analog measurements to an archive is often set at 0.25% to 0.5%,

which is the accuracy of most analog measurements. Audits of archives found analogs set at

2% or at even higher deadbands. This can lead to aliasing and mislead an investigator in

analyzing events. Current historical archiving software is capable of data compression

without significant loss of data. The cost of recording media has become minor.

Older analog inputs channels are frequently 12 bit. That is 0.25% accuracy for the full scale

(1 bit out of 4095 total bits). The system may not be capable of obtaining a desired accuracy

from the analog I/O.. The transmitter accuracy compounds the situation. Assess the analog

input and output capability of the system. It should be at an absolute minimum of 13 bit

accuracy with a preferred accuracy of 15 bits (or more). The accuracy of the measurement is

an important factor in historical archiving, interpreting the data and controlling the process.

In modeling and optimizing generator performance, historical archiving for several years is

required. Seasonal variations and overall control of the generator and dam performance can

only be audited and improved using long term data.


Rev. 1.0, 12/05/2011 291

Table 3: ISA 18-2 Alarm Performance Metrics [6]

3.2 Operations

HMI - Human Machine Interface

The HMI is more than just a rehash of a P&ID (piping and instrumentation design drawing)

with process descriptions. The software helps the operator in routine process management

and optimization. The largest improvement in the HMI for operations has been in helping

the operator respond to alarms. In the last few years emphasis has been placed in developing

HMIs to assist the operator in abnormal situation management, which has been developed in

a consortium with Honeywell [8]. The findings of this group have led to a radical graphical

design change for operators. The normal color conditions for a process is gray and the


Rev. 1.0, 12/05/2011 292

background is gray. Abnormal conditions change color based on the processes. Information

such as efficiencies or key performance indicators often prompt the operator long before a

serious alarm condition occurs. This group concludes that operators respond 40% faster to

alarms than traditional displays with multiple colors and are less likely to make mistakes in

responding to alarms.

Optimization – Various Methods

Below are the minimum control capabilities in an operating system.

Most Efficient Load (MEL)

This control mode will give the majority of efficiency benefits. The automation

system will look at all the variables affecting unit efficiency, compare them to

optimum, and automatically adjust the unit to achieve the highest possible efficiency

for the operating conditions available. The system will continuously monitor all the

parameters and, if any changes occur, it will automatically make necessary

adjustments to again maintain maximum efficiency.

Maximum Sustainable Load (MSL)

While this mode is not the most efficient, there are times, when the unit must be

operated at maximum MW output due to other power system constraints.

Fixed Turbine Flow

Occasionally there is a requirement to operate a plant at a fixed flow rate for periods

of time. If there is only one unit at that plant, there is little opportunity during these

periods to optimize efficiency. However, if there are multiple units at that plant, the

automation system can match the individual unit efficiencies in such a way as to

maximize the total flow requirement for the plant.

Headwater / Tailwater Elevation Control

Occasionally there is a requirement to operate a plant such that a particular

Headwater or Tailwater elevation is achieved. Just like the fixed turbine flow mode

there is little opportunity to optimize efficiency if there is only one unit. But, as long

as several units are available the automation system can match the individual unit

efficiencies to maximize plant efficiency while maintaining the water elevations.

Load Following / Automatic Generation Control

AGC is a topic which has caused much debate over the years among hydro utilities.

The power system operators want to utilize hydro units for AGC due to the rapid

response of the hydro units. Plant operation personnel tend to discourage that

practice due to the belief that it causes increased maintenance requirements and

reduced efficiency. Assuming that AGC is a requirement for the plant being

automated, the automation system can take the load set point supplied by the power


Rev. 1.0, 12/05/2011 293

system and calculate the most efficient loading of the individual units and still

achieve the required AGC needs.

Condensing / Reactive Power Control

Although there is no unit efficiency issue since no water is used in condensing mode,

it is still an operating mode that must be considered in the software design as many

units are operated this way for system voltage stability. In condensing mode, the

turbine gates are closed and depending on the design of the unit, water is either

naturally evacuated or a system of air compressors forces the water below the turbine

blades. The unit is then operated as a synchronous condenser to supply reactive

power to the power system for voltage control.

Automatic Load Reduction and Reinstatement for Temperature Considerations

High temperature conditions for plant equipment is one of the fundamental issues that

must be addressed. By supplying temperature sensors from plant equipment into the

automation system, the system can monitor and trend those temperatures to ensure all

components stay within their safe limits. One feature the automation system can

accomplish is to allow the individual components to operate close to limits, but then

if a temperature limit is reached, reduce loading to allow the temperature to stabilize

at safe levels. Then as conditions change, which affect the cooling of that

component, the automation system can automatically increase the load back to the

desired level. Temperature sensors are almost always included in the generators, unit

transformers, and critical bearings. Others critical to unit operation should be

included as available.

Sequence of Events and First Out

First out information should always be historically archived. This is critical information for

operations and troubleshooting. The first out information for trending originates from the

controller, not from comparing times of discrete alarms in the historical archive. Historical

archiving software is usually not fast enough to analyze events that may take place for high-

speed trips. First out alarming in high-speed applications, such as turbine control, is

configured in the control system. These discrete inputs are most commonly scanned at 1 ms

or faster. Standard discrete I/O is not normally scanned at this frequency.

The main controller should have a time sync program with a GPS clock. This accurate time

should be shared in all the controllers and HMIs.

The control system software frequently has prebuilt SOE (sequence of events) blocks or first

out blocks that capture the event that caused a system to trip or fail. This captured event is

then historically trended and displayed to the operator for a quick analysis as to what just

happened. A turbine can trip off line for many reasons. A high vibration trip will be

programmed in a first out block along with temperatures, speeds, power, operator action etc.

If a trip is caused by high vibration, it will be the trapped event in the first out block and

displayed to the operator. The operator will be able to quickly comprehend the cause of the


Rev. 1.0, 12/05/2011 294

trip and take appropriate action. A restart of the tripped turbine will automatically reset the

first out block and be ready to capture the next trip.

An alternate way of capturing first out events is to wire to an SOE device or high speed I/O

card in parallel to the normal control I/O. The software in the controller (not the historical

archiving software) will capture the individual times of each alarm. The actual time of the

alarm will traditionally be in the message portion of the alarm and not the time the alarm

appears in the archive. The operator will be required to look at all messages of the alarms in

the alarm archive and search for the time of the first event that caused the trip. This is a

common setup in systems that have evolved over the years and in older control systems that

are still in service.

3.3 Maintenance

Backing Up Systems – Disaster Recovery Plans

A disaster recovery plan is essential and must be part of a control system design. A disaster

can occur from a fire, corrupt data, failed systems, poor configuration with a download or

even sabotage. There should be a least two backup copies. On a scheduled basis (monthly or

quarterly, depending on how frequently changes are made to the system) a backup copy

should be made that is stored in a secure location offsite. There are companies that provide

this as a commercial service to IT departments. Primary backups should be made after any

change. Commercial software archiving programs are available to store backups. Images of

PC based systems on a frequent scheduled basis is also recommended. Historical data should

have a backup system as well. A plan for making backups should be made then adhered to.

It is critical to test a recovery system. There are numerous stories of backup systems that

were found to be ineffective. In some cases the backup tapes or disks were found to be blank

or the backup copies were corrupt.

Also, refer to NERC-CIP-009 ―Recovery Plans for Critical Cyber Assets‖

Patches and Software Updates or Changes

The NERC CIP-007-3 standard stresses the need to test modifications before installing the

changes in the field. This is to minimize adverse effects on the production system or its

operation. This includes verifying that no changes impact cyber security. Common

practice to date has been to make changes in a control system without first testing on a bench

or test system. The engineer or programmer has previously assumed no serious error or

complications will occur with a change. This recommended practice of testing, even for a

non-NERC site, will reduce errors in operations and create increased confidence from

operators and management in the quality of process control software changes. In practice,

the authors of this article have found the amount of time to test is quite minimal and has little

impact on perceived productivity of the programmer when the time required to correct errors

in the field with untested changes are taken into account.


Rev. 1.0, 12/05/2011 295

Vendor patches, such as Microsoft, Siemens, Emerson, Honeywell etc, should be tested in a

lab environment before field installation. Some vendors will test their software/hardware

with recent patches and inform customers of the safe installation of the patches.

Documentation

NERC CIP-003-3 standard outlines rigorous documentation requirements. All changes to a

control system need to be documented in a systematic manner.

Secure Passwords

All default passwords and/or administrative logins without passwords must be eliminated.

All administrative passwords must be kept secure. The passwords should be ‗strong‘. An

ideal password is long (8 characters or more) and includes letters, punctuation, symbols, and

numbers. It is permissible to write down passwords as it is difficult to memorize strong

passwords. These written passwords should be stored in a secure place. These documents

containing the passwords must be kept in a secure location. Refer also to NERC CIP-007-3

section 5.3.

Predictive Maintenance Software – Condition Monitoring

Condition monitoring measures the health of an asset through monitoring and analysis of

data. Common data monitoring points are vibration, temperature, wear, corrosion, pressure,

proximity and flow. Newer instrumentation, such as a HART™ enabled digital control valve

positioner, has digital feedback information to monitor hysteresis, valve stiction and

instrument air pressure. Data is monitored in real time to alert operations to potential

problems. Packages are available to predict required maintenance using these data points.

Maintenance is performed only when required.

From Hydro World Vol. 19 Issue 3: ―Most of the 1,560 MW of hydropower plants in Japan

are unmanned. Operations and maintenance of these plants are handled using a wide-area

maintenance system, in which one office manages multiple facilities. Unmanned plants are

equipped with remote monitoring systems that continuously record data from various

devices, such as tailrace level, turbine discharge, and generator vibration. Condition-based

maintenance is used…

Extending the periodic inspection and overhaul cycles makes it possible to reduce the

number of maintenance staff. Reducing the number of man-hours worked by engineers will

enable their centralization to hydro plants and their allocation to maintenance with DEDE

and other organizations. An estimated 2,025 man-hours can be saved by reducing the cycle of

periodic inspections and overhauls. For example, before the demonstration, 2,130 man-hours

were required for periodic inspection; this was reduced to 1,485 man-hours. For overhaul,

3,600 man-hours were required; this was reduced to 2,400 man-hours.‖


Various plant functions are required to be operated quickly and predictably in response to

changes in process variables or operator commands. Failure of the control system to execute a


Rev. 1.0, 12/05/2011 296

programmed response within a specific time frame will result in operator frustration and

dissatisfaction and may jeopardize the safety of personnel and equipment. To ensure that the

control system responds in a manner commensurate with the expectations of plant operations, the

real-time ability of the control system should be defined in terms of the minimum time that it

takes to process field events and operator-entered and program-generated commands.

Controls system response times are typically specified at the plant level. This excludes the

interface with offsite control centers. The response times for offsite control will vary depending

on the type and speed of the interconnecting communications link. In those situations, where the

response time from offsite control centers is critical, it is necessary that the communications

system be designed for secure, high-speed transmission with the plant control system.

The response time of the control system will depend on the system loading at the time of the

event or control action as defined by its CPU and network load rate.

The CPU load rate is typically computed as a percentage of CPU capacity for "normal" and

"worst case" system loading scenarios. A normal operating scenario is defined to be one where

all field values are being updated at the required periodicity, a minimum number of active

windows are open at the operator interface, communications are in normal configuration,

application programs are in operation, and normal plant start/stop operations are being

undertaken. A "worst case" scenario is typically a case where there are multiple unit trips in a

short period of time. Such a condition has the effect of increasing the number of I/O (either field

devices or operator-generated commands) that are simultaneously changing state.

Typical CPU load rates for normal operating scenarios are in the range of 40-60%. Some

controllers set a percentage of CPU for logic and another percentage for communications. For

worst-case loading scenarios, the CPU load rate will typically vary between 50-75% total. The

network load (TCP/IP) should be less than 30% in the worst case scenario.

The time interval between the moments that a command is issued at the operator interface to the

time the feedback (such as motor status) is displayed at the HMI should not exceed 1-2 seconds.

The time interval between the moments that a command has been issued at the operator interface

to the time that the command is transmitted to the field device should be under 1 second. Ideally,

discrete commands should be transmitted to the device in less than 200ms. The majority of I/O

device drivers place a priority on write commands (write commands or operator inputs will

normally execute before read commands) so that there is a quick response in the field to an

operator screen input.

The time interval between the moments that a status change occurs at an input at the control

system I/O to the time that the status change is displayed at one of the operator interfaces, should

not exceed 1-2 seconds.

Update times to the system-wide database should be less than 1 second and typically range from

100 to 500 ms, depending on the type of I/O (digital input, analog input, or accumulator) and

system loading.


Rev. 1.0, 12/05/2011 297

Intrusion detection has historically been strictly an IT (information technology) function. This is

falling upon process control engineers now. Intrusion detection logs should be automated and

inspected by the process control engineer and IT. There should be no successful intrusion

attempts.

Syslogs and firewall logs have also been an IT only function. Process control engineers should

review these on a periodic basis.

Actionable alarms should not exceed 10 per hour. Ideally these alarms should not exceed 6 per

hour per operator.


Baseline Knowledge:

IEEE Std 1249:1996, IEEE Guide for Computer Based Control for Hydroelectric Power

Plant Automation.

IEEE Std 1249:2010 working copy, IEEE Guide for Computer Based Control for

Hydroelectric Power Plant Automation.

FISMA (NIST 800-53), Recommended Security Controls for Federal Information Systems

and Organizations, NIST Special Publication 800-53.

The FISMA Implementation Project was established in January 2003 to produce several

key security standards and guidelines required by the FISMA legislation. As a key

element of the FISMA Implementation Project, NIST also developed additional guidance

(in the form of Special Publications) and a Risk Management Framework which

effectively integrates all of NIST‘s FISMA-related security standards and guidelines in

order to promote the development of comprehensive, risk-based, and balanced

information security programs by federal agencies. The Risk Management Framework

and the associated publications are available at:

http://csrc.nist.gov/publications/PubsSPs.html.

The National Institute of Standards and Technology (NIST) 800-53 provides recommended

security controls of federal information systems and is used to determine the baseline

security controls for the system. Federal IT systems must adhere to these security guidelines

to comply with FISMA. The section that pertains to hydroelectric control systems is in

appendix I of NIST 800-53.

United States Computer Emergency Readiness Team

The continuously updated site: http://www.uscert.gov/control_systems/

The goal of the DHS National Cyber Security Division's CSSP is to reduce industrial

control system risks within and across all critical infrastructure and key resource sectors

by coordinating efforts among federal, state, local, and tribal governments, as well as

industrial control systems owners, operators and vendors. The CSSP coordinates

http://csrc.nist.gov/publications/PubsSPs.html

http://www.uscert.gov/control_systems/


Rev. 1.0, 12/05/2011 298

activities to reduce the likelihood of success and severity of impact of a cyber attack

against critical infrastructure control systems through risk-mitigation activities.

National Communications System, Supervisory Control and Data Acquisition (SCADA)

Systems, NCS Technical Information Bulletin 04-1, Oct. 2004.

http://www.ncs.gov/library/tech_bulletins/2004/tib_04-1.pdf

Hydro Life Extension Modernization Guide, Volume 7 – Protection and Control, EPRI, Palo

Alto, CA: 2000. TR-112350-V7.

State of the Art:

ANSI/ISA ISA 18.00.02-2009 ―Management of Alarm Systems for the Process Industries‖.

Juniper Networks, http://www.juniper.net/us/en/local/pdf/whitepapers/2000276-en.pdf, 2010

ASM Consortium, See http://www.asmconsortium.net. Refer also this white paper:

http://www.asmconsortium.net/Documents/OpInterfaceReqts_GoBeyond_Jan09.pdf

National Institute of Standards and Technology's (NIST) Advanced Technology Program

assisted in funding this technology.

Hydro World Vol. 19 Issue 3

CERN: Large Hadron Collider Project, Power Point Presentation, http://machine-

interlocks.web.cern.ch/machine-

interlocks/Presentations/PIC/Powering%20Interlocks%20Reliability_from_MZS.ppt

Power Engineering, Upgraded SCADA System Gives Hydro Plant Greater Reliability and

Room to Grow, http://www.power-eng.com/articles/print/volume-103/issue-

10/features/upgraded-scada-system-gives-hydro-plant-greater-reliability-and-room-to-

grow.html, 1999

Standards:

IEEE Std 1010:2006, IEEE Guide for Control of Hydroelectric Power Plants

National Electric Reliability Council NERC-CIP 002-009 Summary http://www.nerc.com/

CIP-002-3 ―Critical Cyber Asset Identification‖

Standard CIP-002 requires the identification and documentation of the Critical Cyber

Assets associated with the Critical Assets that support the reliable operation of the Bulk

Electric System. These Critical Assets are to be identified through the application of a

risk-based assessment.

CIP-003-3 ―Security Management Controls‖

Standard CIP-003 requires that Responsible Entities have minimum security management

controls in place to protect Critical Cyber Assets.

CIP-004-3 ―Personnel and Training‖

http://www.ncs.gov/library/tech_bulletins/2004/tib_04-1.pdf

http://www.juniper.net/us/en/local/pdf/whitepapers/2000276-en.pdf

http://www.asmconsortium.net/

http://www.asmconsortium.net/Documents/OpInterfaceReqts_GoBeyond_Jan09.pdf

http://www.power-eng.com/articles/print/volume-103/issue-10/features/upgraded-scada-system-gives-hydro-plant-greater-reliability-and-room-to-grow.html





Rev. 1.0, 12/05/2011 299

Standard CIP-004 requires that personnel having authorized cyber or authorized

unescorted physical access to Critical Cyber Assets, including contractors and service

vendors, have an appropriate level of personnel risk assessment, training, and security

awareness.

CIP-005-3 ―Electronic Security Perimeters‖

Standard CIP-005 requires the identification and protection of the Electronic Security

Perimeter(s) inside which all Critical Cyber Assets reside, as well as all access points on

the perimeter. All access points to the control system need to be documented. It is

common for vendor or remote maintenance dial up access to be tied to a hydro control

system. These should be eliminated whether a facility is under NERC or not. Access

should be secured through firewalls and the use of VPNs. All access should be logged.

CIP-006-3 ―Physical Security of Critical Cyber Assets‖

Standard CIP-006 is intended to ensure the implementation of a physical security

program for the protection of Critical Cyber Assets.

CIP-007-3 ―Systems Security Management‖

Standard CIP-007 requires Responsible Entities to define methods, processes, and

procedures for securing those systems determined to be Critical Cyber Assets, as well as

other other (non-critical) Cyber Assets within the Electronic Security Perimeter(s).

CIP-008-3 ―Incident Reporting and Response Planning‖

Standard CIP-008-3 ensures the identification, classification, response, and reporting of

Cyber Security Incidents related to Critical Cyber Assets.

CIP-009-3 ―Recovery Plans for Critical Cyber Assets‖

Standard CIP-009 ensures that recovery plan(s) are put in place for Critical Cyber Assets

and that these plans follow established business continuity and disaster recovery

FISMA (NIST 800-82), Industrial Control System Security, NIST Special Publication 800-

82, http://csrc.nist.gov/groups/SMA/fisma/ics/documents/oct23-2009-workshop/nist-

ics3_10-23-2009.pdf

http://csrc.nist.gov/groups/SMA/fisma/ics/documents/oct23-2009-workshop/nist-ics3_10-23-2009.pdf

http://csrc.nist.gov/groups/SMA/fisma/ics/documents/oct23-2009-workshop/nist-ics3_10-23-2009.pdf


Machine Condition Monitoring

Revision 1.0, 12/02/2011

HAP – Best Practice Catalog – Machine Condition Monitoring

Rev. 1.0, 12/02/2011 301



1.1.1 Condition Monitoring Components and Measurements ....................................... 302




2.1 Technological Evolution and Design Technology ....................................................... 308




3.2 Operations .................................................................................................................... 310

3.3 Maintenance ................................................................................................................. 313



4.2 Analysis of Data ........................................................................................................... 313

4.3 Integrate Improvements................................................................................................ 313



Rev. 1.0, 12/02/2011 302


Condition monitoring of hydroelectric power generating units is essential to protect against

sudden failure. Fault development can occur very quickly. Many hydro units are located in

remote areas making regular inspection difficult. It is required to have a monitoring system that

continuously checks machine condition, remotely indicates the onset of a fault and provides the

possibility of preventative automatic shutdown.

Hydroelectric turbine-generators are subject to forces and operating conditions unique to their

operation and configuration. They typically operate at low rotational speeds. Their physical

mass and slow rotational speeds give rise to large vibration amplitudes and low vibration

frequencies. This requires a monitoring system with special low frequency response capabilities.


Hydropower Facility → Powerhouse → Instrument and Controls → I&C for Condition

Monitoring

1.1.1 Condition Monitoring Components and Measurements

Performance and reliability related components are primarily centered on the turbine and

generator. The primary components are proximity probes (used for vibration and air

gap), temperature probes and speed indication.

Eddy current transducers (proximity probes) are the choice of vibration transducer and

monitoring. Eddy current transducers are the only transducers that provide shaft relative

(shaft relative to the bearing) vibration measurement.

Several methods are usually available for the installation of eddy current transducers,

including internal, internal/external, and external mounting. Before selecting the

appropriate method of mounting, special consideration needs to be given to several

important aspects of installation that will determine the success of monitoring.

Eddy current transducers work on the proximity theory of operation. An eddy current

system consists of a matched component system: a probe, an extension cable and an

oscillator /demodulator. A high frequency RF (radio frequency) signal is generated by the

oscillator/demodulator, sent through the extension cable and radiated from the probe tip.

Eddy currents are generated in the surface of the shaft. The oscillator/demodulator

demodulates the signal and provides a modulated DC Voltage where the DC portion is

directly proportional to gap (distance) and the AC portion is directly proportional to

vibration. In this way, an eddy current transducer can be used for both radial vibration

and distance measurements such as thrust position and shaft position. [2]


Rev. 1.0, 12/02/2011 303

Figure 1: Typical eddy current transducer curve

Guide Bearing Vibration Probe

By measuring vibration at generator and turbine guide bearings, various sources of

unbalance, shear pin failure, bearing problems and wicket gate problems can be

determined. [1]

Gap

Gap indicates the distance between the probe tip and the shaft. It is determined by

filtering out the dynamic signal (AC portion of the waveform) and looking only at the

DC portion of the waveform. This is shown in Figure 1.

Thrust Bearing Oil Film Thickness

Large vertical hydro units can weigh over 1,000 tons, with the unit‘s entire weight

carried by the thrust bearing. An absence or reduction in oil film thickness at the

thrust pads results in rapid breakdown of the bearing babbit which can further lead to

in rotor/bearing damage if the oil film is not corrected. On hydro units, the thrust

bearing shoes are fitted with proximity probes observing the thrust collar, providing a

measurement of oil film thickness.

Guide Bearing Temperatures

Bearing temperature can indicate problems related to fluid-film bearings, including

overload, bearing fatigue, or insufficient lubrication. One RTD (resistance

temperature device) or thermocouple sensor is installed per bearing pad.

Thrust Bearing Temperatures

Bearing temperature can indicate problems related to fluid-film bearings, including

overload, bearing fatigue, or insufficient lubrication. One RTD or thermocouple

sensor is installed per bearing pad.

Keyphasor® Signal (Trademark Bently-Nevada)

A proximity probe observing a once-per-turn notch or protrusion (such as a key or

keyway) on the machine‘s shaft provides a precise reference signal used for


Rev. 1.0, 12/02/2011 304

indicating rotational speed, filtering vibration to multiples of running speed (such as

1X, NOT 1X, and NX – see definitions below), providing vibration phase information,

and allowing air gap profile data. The proximity transducer is generally mounted

near the upper guide bearing. The shaft‘s notch or projection should align with an

established reference on the rotor such as the generator‘s #1 pole.

1X Amplitude and Phase

This is a measurement of the vibration that is synchronous with rotor speed (1X). A

tracking filter with a Q (see fig. 2.) of 18 is used to attenuate all other components.

This measurement is valid at speeds between 25 rpm and 1500 rpm, which is

applicable for most hydro-turbines. This measurement is used to determine

acceptance regions and provide data for detecting forced vibrations that may be

introduced by bearing wear, unbalance, wicket gate damage, blade damage, generator

faults, debris passing through the machine, and other conditions. An amplitude

and/or phase change can be indicative of the above conditions. [4]

NOT 1X

This is an overall vibration measurement with the 1X component attenuated. This is

a measurement of all vibration components except those occurring at shaft rotative

speed. This measurement uses a tracking filter with a Q of 18 to attenuate the 1X

component. With the 1X signal attenuated, which is usually the predominant

component in hydro-turbines, the remaining signal will be the sub-synchronous

vibration due to rough zone conditions or super-synchronous vibration. Therefore, the

NOT 1X is the primary measurement used for rough zone vibration. Cavitation occurs

during partial loads and running closer or below minimum operating level of the turbine.

That operating range, where cavitation occurs, is considered to be in the rough zone. In

Francis turbines, for example, cavitation damage is visible in the edges of the runner and

draft tube.

In addition to alarm set-points, an option can be implemented on the NOT 1X

measurement for enabling or disabling a trip. This may be used to prevent other

alarming while the hydro-turbine passes through the rough zone. Alarm delays may

also be set to allow time for the hydro-turbine to pass through this zone. [4]

NX (Amplitude and Phase)

This is a measurement of the vibration that is an integer multiple (nX) of the rotor

speed. A tracking filter with a Q of 18 is used to attenuate all other components. ―N‖

may be configured to an integer value selected by the operator. Typically, this is used

to detect guide vane blockage or shear pin failure, but may be used for detection of

other faults that will cause super-synchronous vibrations. One major cause of super-

synchronous vibration is reduced water flow through a wicket gate. This will cause a

low-pressure region, and each time a blade or bucket passes through it, an impulse is

felt on the rotor causing a super-synchronous vibration equal to the

number of blades. Setting ―N‖ to equal the number of blades will cause the NX

amplitude and phase to be detected. [4]


Rev. 1.0, 12/02/2011 305

Composite – Gap and NX

The composite measurement combines the gap and NX amplitude to provide a means

for detecting and alarming on shear pin failure or other types of conditions that

change the flow of water through a wicket gate. In addition to the NX vibration

caused by the newly created low-pressure region, the shaft position will also move

toward that low-pressure area. The gap measurement will detect the change in shaft

position. Composite is simply the NX amplitude multiplied by the percent-change in

the gap. These two major indicators of shear pin failure are combined into one

convenient measurement to provide extra machine protection. [4]

Figure 24: Definition of Q

Head Cover/Draft Tube Vibration

Certain operating conditions can give rise to cavitation, an implosion of vapor

cavities in the liquid. Cavitation can damage the turbine, erode metal, affect

efficiency, and eventually force a shutdown. Cavitation is measured with an

accelerometer mounted on the draft tube. By monitoring for draft tube or head cover

vibration with an accelerometer and filtering appropriately, cavitation can be detected

and conditions can be adjusted to avoid operating the unit in this damaging region.

Stator Frame Vibration

Vibration of the stator core and frame can cause fretting and damage to the winding

insulation. Uneven air gap can also cause the stator core to vibrate. Low-frequency

seismic transducers are mounted on the outer diameter of the stator core and frame.

By mounting an appropriate seismic vibration transducer on the stator core and frame,

such problems can be detected before serious damage occurs.

Generator Temperatures

Temperature sensors are installed in locations such as in stator slots, air cooler inlet

and outlet, water inlet and outlet, etc., providing important information on stator

condition. The system provides alarms and alerts operators when temperatures are

outside of acceptable limits. [1]

The bandwidth, Δf, of a damped oscillator is shown on a graph of energy versus frequency. The Q factor of the damped

oscillator, or filter, is f0 / Δf. The higher the Q, the narrower and 'sharper' the peak is.

Q= f0/Δf. In other words, Q is a filter’s center frequency divided by its bandwidth, and is a measure of how narrowly the filter

can pass the desired frequency and attenuate all other frequencies.


Rev. 1.0, 12/02/2011 306

Cooling Water Flow and Cooling Water Temperature

Cooling water flow may be an interlock and/or a permissive on some systems.

Cooling water temperature tends to be informational only as it varies with ambient

conditions. The quantity of cooling water flow, above the interlock minimum, is a

minor variable in condition monitoring. This flow measurement is normally an

analog device such as a magnetic flow meter or an orifice plate with a differential

pressure measurement converted to flow.

Figure 3: Showing both Turbine and Generator Vibration XY Probes [8]

Radial vibration and position probes are typically located at each bearing in "XY" pairs.

The probes in each XY pair are mounted 90° to each other, thus giving a complete view

of shaft radial vibration and position at the probe pair location.


Rev. 1.0, 12/02/2011 307

Figure 4: Showing X and Y Probes with Internal or External Mounting [2]

Radial vibration measures the basic dynamic motion (vibration) that is perpendicular, i.e.

radial, to the axis of the shaft. The amplitude of radial vibration indicates how "rough or

smooth" the machine is running. On critical plant rotating machinery with proximity

probes, radial vibration is expressed in units of mils (thousandths of an inch) peak-to-

peak displacement.

Radial position provides information about the average position of the shaft within the

bearing clearance. Fluid-film bearings, whether sleeve or tilting pad, have clearance

between the shaft and bearing which permits the shaft to ride at different positions within

the clearance. The average position is a primary indicator of proper machine alignment

and bearing loading, both of which are key to managing vibration to acceptable levels.

The Keyphasor® probe provides the timing marker required to measure the phase angle

of vibration. Accurate phase angle is necessary for in-situ rotor balancing and is

extremely important for analysis of machinery malfunctions.


Best practices for machine condition monitoring can have a significant impact on plant

efficiency and generation. A condition monitoring system can predict a pending failure and

avoid machine stressors, detect deterioration earlier, reduce the length and frequency of

outages, provide root cause analysis and improve availability and overall efficiency. The

system can be used as a predictive maintenance tool to reduce unplanned outages. The

system can be used as a standalone condition monitoring and analysis system or it can be

integrated with the plant‘s automatic control system.


I&C - Automation

Mechanical - Lubrication

Mechanical - Generator


Rev. 1.0, 12/02/2011 308

Mechanical – Governor

Mechanical – Raw Water


2.1 Technological Evolution and Design Technology

Vibration analysis was typically performed by a mechanic or the operator by observing a dial

indicator. This is still the only method in older facilities. Recent developments in vibration

sensor, data acquisition, and analysis technologies, however, are making vibration analysis

cheaper, easier, and more widely available.

Air gap and vibration data is now being incorporated into model-based diagnostics. Models

create virtual sensors where physical sensors are not able to be installed. An example is

where real data from physical sensors mounted on the bearings at the shaft ends, is used to

create a virtual sensor for mid-span vibration.

Detailed analysis is now available in near real time for stator insulation failure, stator

grounding issues and stator vibration. These problems were previously only determined by

expensive shutdowns and testing when the unit is disabled. Even when the unit is down, it

can be very difficult to identify stator problems. The testing is expensive and time

consuming. In the last few years, measuring magnetic flux using a variety of partial

discharge sensors has evolved to be a viable tool for checking for generator problems using

model-based diagnostics.


State of the art cannot be discussed without mentioning the hardware required. Having all

the sensors mounted, as listed below, and tied to supervisory system that has model-based

software is the state of the art.

State of the Art Turbine Measurements: (See Figure 5.)

2-axis guide bearing vibration

Guide bearing temperature

Guide bearing housing seismic

Draft tube vibration (may include head cover vibration)

Rotational speed

Seal ring position/blade clearance

Cooling water flow

Wicket gate position


Rev. 1.0, 12/02/2011 309

Figure 5: Turbine Measurements [1]

State of the Art Generator Measurements (See Figure 6.)

Air gap

2- axis guide bearing vibration

Guide bearing temperatures

Thrust bearing oil film thickness

End winding vibration

Core vibration

Stator frame vibration

Thrust bearing pad temperature

Generator winding temperatures

Magnetic flux or partial discharge probes (various types)

Cooling water flow


Rev. 1.0, 12/02/2011 310

Figure 6: Generator Measurements [1]



The items to assess:

What is installed compared to recommended measurements?

What parameters or variables are available to the control system?

When was it installed? Age of equipment.

How well was it installed? Proper mounting. Noise protection.

Long term data for optimization and measure degradation?

Training of operators? Are they involved in analyzing the data?

Advanced calculations capability for better outage planning?

3.2 Operations

Monitoring systems includes sensors, transducers, monitoring modules and software and

should be fully integrated with a plant‘s governor and control system to facilitate shutdown

and alarming. Many of the vibration behaviors typical to generator units require specialized

filtering and signal conditioning. To minimize inaccurate readings and false warnings, the


Rev. 1.0, 12/02/2011 311

monitoring system must be designed to operate long-term with the expected mechanical

loads in a humid environment. The condition monitoring system should have features to

prevent false alarms. Typically, the vibration signals must exceed preset limits for a specified

time period before warning is given to reduce false trip signals. The monitoring system

should also take into account rough zones that may be experienced due to low loads during

start-ups.

Turbines in hydroelectric power plants must be able to withstand stresses as a result of rapid

starts, stops and partial loading. These stresses induce fatigue that accumulates and

eventually leads to damage. Wear to the journal bearings, damage to the runner blades from

corrosion, cavitation and/or foreign particles in the water supply are other common problems.

In many cases, the damage could be avoided with a condition monitoring system and

methodology.

Air gap is a measure of the distance between rotor and stator in the hydro generator.

Monitoring of air gap is important as both the stator and the rotor on large hydro machines

can be quite flexible, and their shape and location are affected by operating centrifugal,

thermal, and magnetic forces. Off-center or out-of-round conditions will at least reduce

operating efficiency and in more severe cases can lead to damage from magnetically induced

heating or a rotor-to-stator rub. [6]

When a hydro-generator rotor system is balanced and aligned properly, the shaft should spin

within the confines of the guide bearings without much force being exerted against these

bearings. Clearance of guide bearings can be estimated based on data that is acquired during

unit startup. This is because the shaft moves in a random ―orbit‖ throughout the clearance set

by the guide bearings for the first few revolutions during unit startup. Therefore, when

measuring shaft movement for the first few revolutions, (when the radial forces are not

significant because of low speed – e.g. 8 orbits after start-up) guide bearing clearance can be

estimated quite accurately using orbit analysis. This data can be collected for various

temperature conditions of the guide bearings for both cold and hot conditions. [5]

Overall reliability and effective operation of a monitoring and protection system is related to

a variety of factors including the following: required range of transducers, location of XY

transducers, transducer cable routing and available functionality of the monitoring system.

On many hydro-generators, it is simple to replace a transducer if there is an operational

problem. However, for some hydro-generators, transducers have to operate in an enclosed

space, where quick probe replacement can be problematic. Therefore, for hydro-generators, it

is important to consider installing redundant XY-transducers to increase the reliability of the

monitoring and protection system. The redundant transducers can be fixed:

1) Opposite of the current shaft observing XY-transducers, and/or

2) Without significant angular shift when compared to the existing XY-transducers, and/or

3) Without significant axial shift when compared to the existing XY-transducers.

The term ―shift‖ means that the distance between the two sets of probe tips has to be greater

than the probe separation recommendations in the transducer‘s technical documentation. If


Rev. 1.0, 12/02/2011 312

this condition is not met, then an interaction between both transducers can occur, (often

called cross-talk) decreasing signal to noise ratio. [5]

Partial discharge monitoring or analysis (magnetic flux) is a relatively new development. It

requires an advanced software package and a good understanding of the unit being

monitored. It can determine in real time a failure of stator insulation, stator grounding

problems or stator vibration. Stator anomalies, such as stator vibration, are frequently

difficult to isolate when the unit is down for maintenance.

Vibration monitoring remains the most effective technique for detecting the widest range of

machine faults, but a number of other techniques are available for specialized monitoring, as

seen in the Table 1.

Table 1: Condition Monitoring Techniques [9]

Vibration

Air

Gap

Magnetic

Flux

Process

Values Cavitation

Mechanical and Bearing

Unbalance X

Misalignment X

Rotor rub X

Foundation problems X

Loose bearings X

Oil and lubrication

X

Stator or rotor bar problems

X

Generator

Stator bar/core vibration X

Air gap problems

X X

Rotor/stator out of roundness

X

Loose/shorted stator bars or

faulty insulation or stator

vibration

X

Turbine

Turbine runner/blade problems X

Wicket gate problems X

Turbine blade cavitation X

X


Rev. 1.0, 12/02/2011 313

3.3 Maintenance

Air gap dimension along with rotor and stator shape cannot be effectively measured with the

generator out of service because of the combined effects of centrifugal, thermal, and

magnetic forces. Early detection of air gap anomalies will facilitate condition-based

maintenance by providing the user with important machine data necessary to plan for repairs

before scheduled outages. Long term trending of gap and shapes can be correlated with

operating conditions and used in operational and rehabilitation planning. Knowing the rotor

and stator shapes and minimum air gap dimensions provides the operator with the

information needed to remove a machine from service before serious damage like that from a

rotor-to-stator rub occurs. [6]



Failure modes that the condition monitoring system helps predict:

Wicket gate shear pin failures

Cavitation

Blade and shaft cracks

Bearing rub, fatigue and overload

Insufficient bearing lubrication

Mechanical unbalance or misalignment

Seal and discharge ring distortion

Insulation breakdown is the ultimate failure in any power generation device. The following

faults will lead to the eventual breakdown of insulation.

Air gap reduction/rub

Cooling fault

Winding vibration

Insulation aging (not directly measureable)


There are numerous software packages available to analyze data from condition monitoring

sensors. The high speed data can only be analyzed with computer software that creates

charts, calculates variables such as vibration frequencies, changes in air gap etc. Operators

should also be trained to interpret the data and understand how the conditioning monitoring

system functions. The operators will then learn to trust the data and use the data for the best

local decisions for the plant.

4.3 Integrate Improvements

The best way to gain the benefits of a monitoring system is to take advantage of the

economic opportunities offered by various modernization, refurbishment, and new projects to


Rev. 1.0, 12/02/2011 314

introduce the system and to adapt maintenance practices accordingly. The monitoring system

is a major input to a condition-based maintenance program and is a key contributor to

capitalizing on high market prices.

The cost of the monitoring system is low compared with the cost of a new power plant. A

new plant should automatically be equipped with a monitoring system to minimize

maintenance outage periods and to help the unit owner to stay well-informed of the condition

of the equipment. [7]


GE Energy, Condition Monitoring Solutions for Hydro – Bently Nevada Asset Condition

Monitoring, 2005

STI Vibration Monitoring, Eddy Current Transducer Installation,

http://www.stiweb.com/appnotes/PDF%20Files/radial.pdf

Bruel & Kjaer, Permanent Vibration monitoring on a Hydroelectric Generating Set,

http://www.bksv.com/doc/bo0285.pdf

Orbit, Exploring the New 3500 Hydro Monitor, 3rd

Quarter 2000, http://www.ge-

mcs.com/download/monitoring/3q00cohen.pdf

Orbit, XY Measurements for Radial Position and Dynamic Motion in Hydro Turbine Generators,

Vol. 30 No. 1, 2010

GE Fact Sheet, Hydro Generator Air Gap Monitoring, http://www.gepower.com/o&c/hydro

Hydro World, Equipment Monitoring: Equipment Condition Monitoring: Sharing Experience,

http://www.hydroworld.com/index/display/article-display/361643/articles/hydro-review/volume-

27/issue-2/feature-articles/equipment-monitoring-equipment-condition-monitoring-sharing-

experience.html

Orbit, Condition Monitoring for Hydro Machinery, 2nd

Quarter, 2004

Bruel & Kjaer Vibro, Monitoring Solutions, http://www.bkvibro.com/monitoring-

solutions/industries/power-generation/hydroelectric-power-generation/faults-detected.html

Hydro Life Extension Modernization Guide, Volume 7 – Protection and Control, EPRI, Palo

Alto, CA: 2000. TR-112350-V7.

http://www.stiweb.com/appnotes/PDF%20Files/radial.pdf

http://www.bksv.com/doc/bo0285.pdf

http://www.ge-mcs.com/download/monitoring/3q00cohen.pdf

http://www.ge-mcs.com/download/monitoring/3q00cohen.pdf

http://www.gepower.com/o&c/hydro

http://www.hydroworld.com/index/display/article-display/361643/articles/hydro-review/volume-27/issue-2/feature-articles/equipment-monitoring-equipment-condition-monitoring-sharing-experience.html



http://www.bkvibro.com/monitoring-solutions/industries/power-generation/hydroelectric-power-generation/faults-detected.html

http://www.bkvibro.com/monitoring-solutions/industries/power-generation/hydroelectric-power-generation/faults-detected.html

Rev. 1.0, 12/20/2011

315


Francis Turbine Aeration

Revision 1.0, 12/20/2011

HAP – Best Practice Catalog – Francis Turbine Aeration

Rev. 1.0, 12/20/2011 316



1.1.1 Components of a Francis Turbine Aeration System ............................................. 317


1.2.1 Best Practices Related to Performance/Efficiency and Capability .................. 321

1.2.2 Best Practices Related to Reliability and Operations & Maintenance ............ 321



2.1 Technology Evolution .................................................................................................. 322




3.2 Operations ................................................................................................................. 326

3.3 Maintenance .............................................................................................................. 327

4.0 Metrics, Monitoring, and Analysis .................................................................................. 327


4.2 Data Analyses ............................................................................................................... 328




Rev. 1.0, 12/20/2011 317


This best practice for Francis turbine aeration addresses the technology, condition assessment,

operations, and maintenance best practices with the objective to maximize the unit performance

and reliability. The primary purpose of a Francis turbine aeration system is to provide air into the

turbine as a way of increasing the downstream dissolved oxygen (DO) level for environmental

enhancement.

Hydropower plants likely to experience problems with low DO include those with a reservoir

depth greater than 50 feet, power capacity greater than 10 MW, and a retention time greater than

10 days [3, 6]. In general, these include plants with watersheds yielding moderate to heavy

amounts of organic sediments and located in a climate where thermal stratification isolates

bottom water from oxygen-rich surface water. At the same time, organisms and substances in the

water and sediments consume and lower the DO in the bottom layer. For plants with bottom

intakes, this low DO water often creates problems downstream from the reservoir, including

possible damage to aquatic habitat. Most of the hydropower plants experiencing problems with

low DO have Francis turbines. Typically, the most cost-effective method for increasing the

downstream DO level is to use some form of Francis turbine aeration [9, 11].

A Francis turbine aeration system‘s design, operation, and maintenance provide the most

significant impact to the efficiency, performance, and reliability for a hydro unit utilizing the

system. Aerating Francis turbines can experience insignificant to moderate (approx. 0.2% - 1%)

efficiency losses even without aeration due, for example, to baffles or thicker blades compared to

conventional, non-aerating technology. Aerating Francis turbines can experience significant (3%

to 10% or more) efficiency losses with aeration, depending on the amount of air introduced into

the turbine and the locations where the air is introduced [1, 2, 3, 4]. Francis turbines aerating

through existing vacuum breaker systems and Francis turbines retrofitted for aeration using hub

baffles typically experience restrictions in both capacity and flexibility that can significantly

reduce generation [1, 2, 3, 4, 5, 6, 9, 11, 12].


Hydropower Facility → Powerhouse → Power Train Equipment → Turbine → Francis

Turbine → Aeration Devices (Francis Turbine Aeration System)

1.1.1 Components of a Francis Turbine Aeration System

A Francis turbine aeration system can be either active or passive in design. An active

design includes some type of motorized blower or compressor to force air into the turbine

for mixing with water in the turbine and/or draft tube. The far more common passive

design emphasized in this best practice typically includes either (1) additions or

modifications to the turbine runner or draft tube to create zones of localized low pressure

and draw atmospheric air into the turbine (see hub baffles in Figure 1) or (2) a turbine

runner specifically designed for aeration (see Figure 2). The components of a Francis

turbine aeration system affecting performance and reliability typically consist of air

intakes, air flow instrumentation, sound mufflers, control valves, and air supply piping, as

shown in Figure 3.


Rev. 1.0, 12/20/2011 318

Figure 1: Photograph of Francis Turbine with Hub Baffles and Diagrams Showing Streamlined and Flat

Plate Baffles [6]

Figure 2: Sectional View of Francis Turbine with Central Aeration (Red, Vacuum Breaker; Blue, Shaft),

Peripheral Aeration (Yellow), and Distributed Aeration (Green) [9]


Rev. 1.0, 12/20/2011 319

Figure 3: Typical Configuration for a Francis Turbine Aeration System [7]

Air Intakes: Properly designed air intakes, typically bellmouths, reduce the noise levels

associated with the air flow and reduce pressure losses in the aeration system, which

increases air flow through the aeration system. If a standard nozzle design is used for the

intake or if the intake is properly calibrated, the intake can also be used for air flow

measurement (see Figure 4), which is discussed in the following section.

Air Flow Instrumentation: A variety of technologies can be used for air flow

measurements, including bellmouth inlets, Venturi meters, orifice plates, air velocity

traverses (typically using a Pitot-static tube or hot-film anemometer), calibrated elbow

meters (calibrate off-site with appropriate upstream piping or calibrate in place with

velocity traverses), and calibrated single-point velocity measurements (calibrate off-site

with appropriate upstream piping or calibrate in place with velocity traverses). The

following instruments may also be required for air flow measurements, depending on the

type of air flow meters selected for the aeration system:

Manometers, mechanical differential pressure gages, or electronic differential

pressure cells (preferred);

Thermometers, thermistors, RTDs, or thermocouples for air temperature

measurements at primary flow elements;

Barometer, mechanical pressure gage, or electronic pressure cell for air pressure

measurements at primary flow elements; and

Psychrometer or other means to determine relative humidity at primary flow

elements.

Bellmouth (typ.) for loss

and noise reduction


and noise reduction

Control valveControl valve

Muffler for noise reductionMuffler for noise reduction

Section for measuring air flowSection for measuring air flow


and noise reduction


and noise reduction

Control valveControl valve

Muffler for noise reductionMuffler for noise reduction

Section for measuring air flowSection for measuring air flow


Rev. 1.0, 12/20/2011 320

Figure 4: Inlet nozzle and differential pressure cell for determining air flow [7]

Detailed instructions, equations, and charts useful for understanding air flow

measurements are provided in ASME 1983 [14] and Almquist et al. 2009 [15]. Although

the performance test code for turbines and pump-turbines, ASME PTC 18-2011 [16],

does not currently include turbine aeration systems, a revision addressing aeration

systems is underway [13].

Sound Mufflers: The function of the sound mufflers is to reduce the noise levels

associated with air flows into the Francis turbine aeration system. A properly designed

muffler will reduce noise to a safe level without significantly decreasing the air flow.

Control Valves: The control valves are used to turn on or shut off the air flows into a

Francis turbine aeration system or to regulate the amount of air flow in the system.

Control valves may be manually operated, remotely operated, or integrated into the

plant‘s control system.

Air Supply Piping: The Francis Turbine Best Practice discusses the role of the vacuum

breaker system for drawing in atmospheric air at low gate openings to reduce vibration

and rough operation. Due to the air piping sizes in typical vacuum breaker systems, a

retrofitted vacuum breaker system, even with the addition of hub baffles, rarely supplies

enough air to produce a significant increase in downstream DO. Both retrofitted aeration

systems and aerating turbines typically require additional air supply piping, as shown in

Figures 2 and 3.


Rev. 1.0, 12/20/2011 321


1.2.1Best Practices Related to Performance/Efficiency and Capability

Best practices related to performance/efficiency and capability are similar to the

Francis Turbine Best Practice, with the addition of aerating operation:

Establish accurate current unit performance characteristics and limits under

both aerating and non-aerating conditions through periodic testing [13, 16].

Disseminate accurate unit performance characteristics under both aerating and

non-aerating conditions to unit operators, local and remote control systems,

decision support systems, and other personnel and offices that influence unit

dispatch or generation performance.

Conduct real-time monitoring and periodic analyses of unit performance under

both aerating and non-aerating conditions at Current Performance Level (CPL) to

detect and mitigate deviations from expected efficiency for the Installed

Performance Level (IPL) due to degradation or instrument malfunction.

Periodically compare the CPL under both aerating and non-aerating conditions to

the Potential Performance Level (PPL) under both aerating and non-aerating

conditions to trigger feasibility studies of major upgrades.

Maintain documentation of IPL under both aerating and non-aerating conditions

and update when modification to the equipment (e.g., hydraulic profiling, draft

tube slot fillers, unit upgrade)or the aeration system (e.g., additional air piping,

modifications to hub baffles or draft tube baffles, aerating unit upgrade) is made.

1.2.2Best Practices Related to Reliability and Operations & Maintenance

Use ASTM A487 / A743 CA6NM stainless steel to manufacture Francis turbine

runners to maximize resistance to cavitation, and cavitation-enhanced corrosion.

Clad aeration discharge areas with stainless steel to mitigate cavitation-enhanced

corrosion.

Monitor trends for air flows under similar operating conditions to detect aeration

system problems.

Routinely inspect air intakes, mufflers, air piping, and air outlets and remove any

obstructing debris for optimal performance.





Rev. 1.0, 12/20/2011 322


2.1 Technology Evolution

In the 1950s, turbine venting through the vacuum breaker system was introduced in

Wisconsin to reduce the water quality impact of discharges from the pulp and paper industry

and from municipal sewage systems. Research was also conducted in Europe to develop

turbine designs that would boost dissolved oxygen levels in water passing through low head

turbines. By 1961, turbine aeration systems were operating in the U. S. at eighteen

hydroplants on the Flambeau, Lower Fox, and Wisconsin. During the late 1970s and early

1980s, the Tennessee Valley Authority (TVA) developed small, streamlined baffles, called

hub baffles, which reduced energy losses while increasing air flows and operating range for

aeration. The hub baffles installed at TVA‘s Norris Project (see Figure 1) provided DO

uptakes averaging 2 to 3 mg/L with typical efficiency losses of 1 to 2% [1].

During the mid-1980s, Voith Hydro Inc. and TVA invested in a joint research partnership to

develop improved hydro turbine designs for enhancing DO concentrations in releases from

Francis-type turbines. Scale models, numerical models, and full-scale field tests were used in

an extensive effort to validate aeration concepts and quantify key parameters affecting

aeration performance. Specially-shaped geometries for turbine components were developed

and refined to enhance low pressures at appropriate locations, allowing air to be drawn into

an efficiently absorbed bubble cloud as a natural consequence of the design and minimizing

power losses due to the aeration. TVA‘s Norris Project, which was scheduled for unit

upgrades, was selected as the first site to demonstrate these ―auto-venting‖ or ―self-aerating‖

turbine technologies. The two Norris aerating units contain options to aerate the flow through

central, distributed, and peripheral air outlets, as shown in Figure 2.

The successful demonstration of multiple technologies for turbine aeration at TVA‘s Norris

Project in 1995 has helped to develop market acceptance for aerating turbines. Major turbine

manufacturers who currently offer aerating turbines include ALSTOM, American Hydro,

Andritz, and Voith Hydro.

Performance levels for aerating turbine designs can be stated at three levels as follows:


characteristics at the time of commissioning, under aerating and non-aerating

conditions. These may be determined from reports and records of efficiency and/or

model testing conducted prior to and during unit commissioning.


performance characteristics determined by unit efficiency and air flow testing, under

aerating and non-aerating conditions. This requires the simultaneous measurement of

water flow, air flow, head, and power under a range of operating conditions, as

specified in the standards referenced in this document [14, 15, 16].


to new aerating turbine design information from the turbine manufacturer to establish


Rev. 1.0, 12/20/2011 323

the achievable unit performance characteristics of the replacement turbine under

aerating and non-aerating conditions.


For aerating Francis turbines, turbine efficiencies under aerating and non-aerating conditions

are the most important factor in an assessment to determine rehabilitation and replacement,

as well as proper operation.

When properly designed, hub baffles typically reduce efficiency by 0.5% to 1% without

aeration and 5% or more with aeration, depending on the air flows [1, 2, 3, 4, 5, 9]. In the

cross-section through an aerating Francis turbine shown in Figure 2, central aeration through

the turbine‘s vacuum breaker system is shown in red, and central aeration through the shaft is

shown in blue. Using an existing vacuum breaker system is typically the aeration option with

the lowest initial cost. However, central aeration has the largest effect on unit efficiency, and

the capacity and operational range for the turbine may be severely limited [1, 2, 3, 11, 12].

Figure 2 also shows peripheral aeration in yellow and distributed aeration through the trailing

edges of the turbine blades in green. Distributed aeration often has the smallest effect on unit

efficiency and the highest oxygen transfer into the water (i.e., increased DO), followed by

peripheral aeration [11, 12]. For example, a recent study compared the central, peripheral,

and distributed aeration systems needed to provide a 5 mg/L DO increase for a plant in the

southern USA [12]. In the vicinity of the maximum efficiency, the predicted air flow

requirements (i.e., void fraction in %) for central, peripheral, and distributed aeration systems

were 7.2%, 6.9%, and 6.5%, respectively. The corresponding efficiency decreases (i.e., non-

aerating efficiency minus aerating efficiency, in %) were greater than 10%, 7.4%, and 3.4%,

respectively. These predictions are consistent with field test results reported for other sites [6,

8, 11].

In another example, aerating and non-aerating performance testing was conducted according

to ASME PTC-18 standards [16] at a hydro plant with multiple types of aerating runners,

including two eighty-years-old original runners retrofitted for central aeration, two modern

runners installed in 2002 and designed for central aeration, and four state of the art runners

installed in 2008 with distributed aeration (see Figure 5) through the trailing edges of the

runners [11].

Figure 6 shows the aerating and non-aerating turbine efficiencies versus turbine outputs for

the three unit types at this plant, operating at a net head of 95 ft. The turbine efficiencies have

been normalized to the maximum measured efficiency of the most efficient unit. Note the

relative efficiencies for the three unit types, the relative effects of aeration on efficiency for

central and distributed aeration systems, and the relative amounts of air aspirated by the three

unit types. Under non-aerating operation, the 2008 replacement runners (distributed aeration)

have the highest peak efficiency, with both the original turbines (retrofitted central aeration)

and the 2002 replacement runners (designed central aeration) about 4% lower. Under

aerating


Rev. 1.0, 12/20/2011 324

Figure 5: State of the Art Aerating Turbine with Distributed Aeration

Figure 6: Normalized Turbine Efficiencies versus Turbine Output for Three Unit Types [11]

Net Head Efficiency Test Results (Central and Distributed Aeration)Net Head = 95 ft

0.70

0.75

0.80

0.85

0.90

0.95

1.00

1.05

1.10

10 15 20 25 30 35 40

Turbine Output (MW)

No

rma

lize

d N

et

He

ad

Tu

rbin

e E

ffic

ien

cy

2002 Upgraded Unit, Central Aeration Off

2002 Upgraded Unit, Central Aeration On (Qa/Qw = 2.7% to 4.4%)

Original Unit, Central Aeration Off

Original Unit, Central Aeration On (Qa/Qw = 0% to 3.1%)

2008 Upgraded Unit, Distributed Aeration Off

2008 Upgraded Unit, Distributed Aeration On (Qa/Qw = 5.0% to 7.4%)


Rev. 1.0, 12/20/2011 325

operation, peak efficiencies for the 2008 replacement runners, the 2002 replacement runners,

and the retrofitted original units drop by about 2.5%, 7%, and 2% (with very low air flows

for the retrofitted original units), respectively. Air flow to water flow ratio ranges under

aerating operation for the 2008 replacement runners, the 2002 replacement runners, and the

retrofitted original runners are 5.0% - 7.4%, 2.7% - 4.4%, and 0% - 3.1%.

The operational challenges for efficient power operation and effective environmental

operation of the plant‘s eight units under non-aerating and aerating conditions, over a range

of heads, and with rapid load swings are apparent, emphasizing the importance of proper

control system design.



After the commercial operation begins, how an aerating Francis turbine is operated and

maintained will have a major impact on reducing efficiency losses and maintaining

reliability. Materials for turbine runners are usually cast iron, steel, or stainless steel. As a

best practice, the most common material being used today for new state of the art runners is

ASTM A487 / A743 CA6NM stainless steel (see Francis Turbine Best Practice).

Aeration systems for Francis turbines can take the form of more complex and more energy-

consumptive active systems, such as motorized blowers, to the less complex passive systems,

such as baffles and aerating runner designs. Focusing on the most common aeration system

designs (i.e., passive systems), a simple condition assessment includes inspections of the air

intakes, the air discharge passages in the turbine, the dissolved oxygen monitoring

equipment, and any observable cavitation or corrosion-related damage that might affect

normal operation. A decrease in the expected dissolved oxygen uptake in the waterway

downstream from the plant is a good indicator of degradation in the condition of the aeration

device.

A comprehensive condition assessment for a Francis turbine aeration system requires

information on:

(1) the plant‘s environmental and regulatory environment, including

incoming DO, TDG, and water temperature levels throughout the year

measurement locations and methods for incoming DO, TDG, and temperature

(typically, multiple locations in penstock or spiral case)

regulatory requirements for downstream DO, TDG, and temperature

measurement locations and methods for downstream DO, TDG, and temperature

record of compliance and non-compliance;

(2) the plant‘s operational environment, including


Rev. 1.0, 12/20/2011 326

daily and seasonal operational patterns

typical tailwater range during periods of aeration

other restrictions affecting operations (e.g., rough zones, special requirements for

functioning of aeration systems);

(3) details of the specific aeration system, including

type of aeration system (e.g., vacuum breaker, hub baffles, central, peripheral,

distributed, multiple methods)

diameters and lengths of aeration piping

control valve characteristics;

(4) environmental and hydraulic performance of the specific aeration system, including

pressures at aeration outlets over the operational range

head losses for the aeration piping

air flows through the aeration piping as a function of tailwater elevation, water

flow, and control valve position

turbine efficiency without aeration as a function of power and head

turbine efficiency with aeration as a function of power, head, and air flow

DO uptake over the range of operational conditions

Corresponding TDG levels over the range of operational conditions.

3.2 Operations

Because aerating Francis turbines typically have a narrow operating range for peak efficiency

(see Figure 6, for example), it is extremely important to proved plant operators or automated

control systems with accurate operating curves for the units under aerating and non-aerating

conditions. The curves usually originate from the manufacturer‘s model test data and from

post-installation performance testing. Because turbine performance can degrade over time,

periodic performance testing must be carried out to determine unit efficiencies and to update

the performance curves used for operational decisions. The ten-year testing cycle

recommended in the Francis Turbine Best Practice is typically appropriate.

Francis turbine aeration systems may be operated manually or the operation may be

integrated into a plant‘s control system. The detailed aeration instrumentation and controls

are site-specific. Aeration systems are often operated conservatively to ensure that

environmental requirements for DO levels are maintained. However, this can lead to higher

levels of total dissolved gases (TDG), as well as unnecessary efficiency losses due to

excessive air flows into the turbine. Some sites have TDG environmental requirements in


Rev. 1.0, 12/20/2011 327

addition to DO requirements, and the TDG requirements can have an additional negative

impact on plant operation and further reduce overall plant efficiency.

3.3 Maintenance

For Francis turbine aeration systems, all air flow intakes and passageways must be clean and

free from obstructions to operate properly. Normal maintenance of a Francis turbine aeration

system includes periodic inspection (during routine inspections) and testing of components to

ensure that the aeration system is operating according to design. Areas adjacent to the air

discharge locations in the turbine or draft tube must be monitored for damage due to

cavitation-influenced corrosion. As a best practice, the area surrounding the air discharge

locations should be clad with stainless steel to mitigate damage.

The associated instrumentation for Francis turbine aeration systems, including incoming DO

levels, compliance point DO levels, air flow rates, air valve control, and air valve positions,

must be calibrated and maintained in good working order. Instrumentation for hydraulic

performance data, including unit water flow rates, headwater elevations, tailwater elevations,

and unit powers, must also be calibrated and maintained in good working order. Data on

incoming DO levels, air valve positions, air flow rates, and air temperatures should be

recorded at time intervals that can be correlated with other relevant plant data. As a best

practice, hydraulic performance data and environmental performance data (incoming DO

levels, compliance point DO levels, compliance point TDG levels, unit air flow rates, air

temperatures) should be simultaneously recorded and stored in a common database.

4.0 Metrics, Monitoring, and Analysis


The fundamental performance measurement for a hydro turbine is described by the efficiency

equation, which is defined as the ratio of the power delivered by the turbine to the power of

the water passing through the turbine. The general expression for this efficiency (η) is

where P is the output power, ρ is the density of water, g is the acceleration of gravity, Q is

the water flow rate through the turbine, and H is the head across the unit [16].

The condition of an aerating Francis turbine can be monitored by the Condition Indicator

(CI) as defined according to the HAP Condition Assessment Manual [10].

Unit reliability characteristics, as judged by the unit‘s availability for generation, can be

monitored by use of the North American Electric Reliability Corporation (NERC)

performance indicators, such Equivalent Availability Factor (EAF) and Equivalent Forced

Outage Factor (EFOR), which are used universally by the power industry. However, hydro

plant owners typically do not designate whether or not their Francis are aeration-capable and

do not differentiate between aerating and non-aerating operation.


Rev. 1.0, 12/20/2011 328

4.2 Data Analyses

The key measurements for hydraulic performance include headwater elevation, HHW (ft);

tailwater elevation, HTW (ft); water flow rate through Unit N without aeration, QN (cfs);

power output for Unit N without aeration, PON; and TH, the measurement timestamp for

hydraulic data. The key measurements for environmental performance include incoming DO

level for Unit N, LDON (mg/L); incoming TDG level for Unit N, LTDGN (%); incoming water

temperature, FWTN (degrees F); downstream DO level for plant at the compliance location,

LDOC (mg/L); downstream TDG level, LTDGC (%) at the compliance location; and

downstream water temperature, FWTC (degrees F), at the compliance location; air flow rate

through Unit N, QAN (cfs); water flow rate through Unit N with aeration, QNA (cfs); power

output for Unit N with aeration, PONA; and TE, the measurement timestamp for

environmental data. Measurements can be near real-time or periodic (hourly, daily),

depending on the site details, license requirements, and operational requirements.

The unit efficiency ηN (nondimensional) for operation without aeration is:

ηN = PON/[KρgQN(HHW - HTW)/(1,000,000)]

where K is a dimensional constant, ρ is the density of water at Unit N, and g is the acceleration

of gravity at Unit N. For most cases, using Kρg = 84.5 provides satisfactory results.

The unit efficiency ηNA (nondimensional) for operation with aeration is:

ηNA = PONA/[KρgQN(HHW - HTW)/(1,000,000)]

References provide detailed guidance on performing the key hydraulic measurements [16]

and the key environmental measurements [15].

The unit efficiency loss due to aeration is equal to ηN minus ηNA for a given power level.

However, detailed data analyses are required to determine what portion of these efficiency

losses are avoidable, due to over-aeration, suboptimization, etc., and to compute the associated

revenue losses. In general, aeration-induced efficiency losses greater than 3% warrant further

investigation. The costs associated with the aeration-induced efficiency losses, capacity

losses, and reductions in operational flexibility should be established for comparison with the

associated revenue losses and used to optimize aeration operations and to evaluate and justify

new aeration systems, including turbine replacements.

The condition assessment of an aerating Francis turbine is quantified through the CI, as

described in the HAP Condition Assessment Manual [10]. The overall CI is a composite of

the CI derived from each component of the turbine. This methodology can be applied

periodically to derive a CI snapshot of the current turbine condition so that it can be

monitored over time and studied to determine condition trends that can impact performance

and reliability.





Rev. 1.0, 12/20/2011 329


Data on lost efficiency, lost capacity, and operational restrictions due to Francis turbine

aeration systems can be used to quantify lost revenues from generation and ancillary services,

and the economic losses can be used to evaluate and justify funding for aeration system

improvements, including turbine replacement.


limits. Optimally, the updated results would be integrated into an automated control system.

If an automated control system is not available, hard copies of the updated curves and limits

should be made available to all relevant personnel, particularly unit operators, and the

importance of the updated results should be emphasized, discussed, and confirmed.


Baseline Knowledge:

Bohac, C. E., J. W. Boyd, E. D. Harshbarger, and A. R. Lewis, Techniques for Reaeration of

Hydropower Releases, Technical Report No. E-83-5, Vicksburg, Mississippi: U. S. Army

Corps of Engineers, February 1983.

Wilhelms, S. C., M. L. Schneider, S. E. Howington, Improvement of Hydropower Release

Dissolved Oxygen with Turbine Venting, Technical Report No. E-87-3, Vicksburg,

Mississippi: U. S. Army Corps of Engineers, March 1987.

EPRI, Assessment and Guide for Meeting Dissolved Oxygen Water Quality Standards for

Hydroelectric Plant Discharges, Report No. GS-7001, Palo Alto, California:

ElectricPower Research Institute (EPRI), November 1990.

Carter, J., ―Recent Experience with Hub Baffles at TVA,‖ ASCE Proceedings of Waterpower

95, San Francisco, California, July 25-28, 1995.

EPRI, Maintaining and Monitoring Dissolved Oxygen at Hydroelectric Projects: Status

Report, Report No. 1005194, Palo Alto, California: Electric Power Research Institute

(EPRI), May 2002.

State of the Art:

Hopping, P. N., P. A. March and P. J. Wolff, “Justifying, Specifying, and Verifying

Performance of Aerating Turbines,” Proceedings of HydroVision 98, Reno, Nevada, July

28-31, 1998.

March, P. A., R. K. Fisher, and V. G. Hobbs, ―Water and Energy Infrastructure: Meeting

Environmental Challenges for a Sustainable Water and Energy Future,‖ USACE 2003

Infrastructure Systems Conference, Las Vegas, Nevada, May 6-8, 2003.

Foust, J. M., R. K. Fisher, P. M. Thompson, M. M. Ratliff, and P. A. March, ―Integrating

Turbine Rehabilitation and Environmental Technologies: Aerating Runners for Water

Quality Enhancement at Osage Plant,‖ Proceedings of Waterpower XVI, Spokane,

Washington, July 27-30, 2009.


Rev. 1.0, 12/20/2011 330

March, P. A., Hydropower Technology Roundup Report: Technology Update on Aerating

Turbines, Report No. 1017966, Palo Alto, California: Electric Power Research Institute,

2009.

ORNL et al., HAP Condition Assessment Manual, October, 2011.

March, P. A., ―Hydraulic and Environmental Performance of Aerating Turbine

Technologies,‖ EPRI-DOE Conference on Environmentally-Enhanced Hydropower

Turbines: Technical Papers, Palo Alto, California: Electric Power Reaearch Institute

(EPRI) and Washington, D.C.: U. S. Department of Energy (DOE), Report No. 1024609,

December 2011.

Foust, J. M., and S. Coulson, ―Using Dissolved Oxygen Prediction Methodologies in the

Selection of Turbine Aeration Equipment,‖ EPRI-DOE Conference on Environmentally-

Enhanced Hydropower Turbines: Technical Papers, Palo Alto, California: Electric

Power Reaearch Institute (EPRI) and Washington, D.C.: U. S. Department of Energy

(DOE), Report No. 1024609, December 2011.

Kirejczyk, J., ―Developing Environmental Standards and Best Practices for Hydraulic

Turbines,‖ EPRI-DOE Conference on Environmentally-Enhanced Hydropower Turbines:

Technical Papers, Palo Alto, California: Electric Power Reaearch Institute (EPRI) and

Washington, D.C.: U. S. Department of Energy (DOE), Report No. 1024609, December

2011.

Standards:

ASME, Fluid Meters: Their Theory and Application, New York, New York: American

Society of Mechanical Engineers (ASME), 1983.

Almquist, C. W., P. N. Hopping, and P. J. Wolff, ―Draft Test Code for Aerating

Hydroturbines,‖ TVA Report No. WR98-1-600-125, Norris, Tennessee: Tennessee

Valley Authority (TVA), August 1998.

ASME, Performance Test Code 18: Hydraulic Turbines and Pump-Turbines, ASME PTC

18-2011, New York, New York: American Society of Mechanical Engineers (ASME),

2011.

NERC, Appendix F: Performance Indexes and Equations, January 2011.


Rev. 1.0, 1/20/2012 331

For overall questions

please contact:

Brennan T. Smith, Ph.D., P.E.

Water Power Program Manager

Oak Ridge National Laboratory

865-241-5160

[email protected]

or

Qin Fen (Katherine) Zhang, Ph. D., P.E.

Hydropower Engineer

Oak Ridge National Laboratory

865-576-2921

[email protected]